00. api purchasing guideline handbook.pdf

Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130

American Petroleum Institute Handbook Revision 09.18.04Purchase API Specs online at www.global.ihs.com

Purchasing Guidelines

API Monogram Equipment

Handbook


American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Purchase API Specs online at www.global.ihs.comAPI Monogram Equipment

Special Notes iGuidelines for Using API Publications

Introduction iiiPractical Guidelines for Making Practical Choices

API Spec 2B 2B-1Fabrication of Structural Steel Pipe

API Spec 2C 2C-1Specification for Offshore Pedestal Mounted Cranes

API Spec 2H 2H-1Carbon Manganese Steel Plate for OffshorePlatform Tubular Joints

API Spec 2MT1 2MT1-1Carbon Manganese Steel Plate with Improved Toughness for Offshore Structures

API Spec 2MT2 2MT2-1Rolled Shapes with Improved Notch Toughness

API Spec 2W 2W-1Steel Plates for Offshore Structures, Produced byThermo-Mechanical Control Processing (TMCP)

API Spec 2Y 2Y-1Steel Plates, Quenched-and-Tempered,for Offshore Structures

API Spec 4F 4F-1Drilling and Well Servicing Structures

API Spec 5CT 5CT-1Specification for Casing and Tubing

API Spec 5D 5D-1Specification for Drill Pipe

API Spec 5L 5L-1Line Pipe

API Spec 5LC 5LC-1CRA Line Pipe

API Spec 5LCP 5LCP-1Coiled Line Pipe

API Spec 5LD 5LD-1CRA Clad or Lined Steel Pipe

Table of

Contents

API Spec 6A 6A-1Wellhead and Christmas Tree Equipment

API Spec 6D 6D-1Specification for Pipeline Valves

API Spec 6H 6H-1End Closures, Connectors, and Swivels

API Spec 7 7-1Rotary Drill Stem Elements

API Spec 7K 7K-1Specification for Drilling and Well Servicing Equipment

API Spec 8A 8A-1Drilling and Production Hoisting Equipment

API Spec 8C 8C-1Drilling and Production Hoisting Equipment(PSL 1 and PSL2)

API Spec 9A 9A-1Specification for Wire Rope

API Spec 11B 11B-1Sucker Rods

API Spec 11D1 11D1-1Petroleum and Natural Gas Industries Downhole Equipment Packers and Bridge Plugs

API Spec 11L6 11L6-1Electric Motor Prime Mover for BeamPumping unit Service

API Spec 11N 11N-1Lease Automatic Custody Transfer (LACT) Equipment

API Spec 12B 12B-1Bolted Tanks for Storage of Production Liquids

API Spec 12D 12D-1Field Welded Tanks for Storage of Production Liquids

API Spec 12F 12F-1Shop Welded Tanks for Storage of Productino Liquids

API Spec 12GDU 12GDU-1Glycol-Type Gas Dehydration Units

(Continued to next page)

Page No. Page No.

For updates to the Purchasing Guidelines Handbook, visit the Addenda and Errata section of www.api.org/cat

Table of Contents


American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Purchase API Specs online at www.global.ihs.comAPI Monogram Equipment

API Spec 12K 12K-1Indirect-Type Oil Field Heaters

API Spec 12L 12L-1Vertical and Horizontal Emulsion Treaters

API Spec 12P 12P-1Figberglass Reinforced Plastic Tanks

API Spec 14A 14A-1Specification for Subsurface Safety Valve Equipment

API Spec 14L 14L-1Lock Mandrels and Landing Nipples

API Spec 15HR 15HR-1High Pressure Fiberglass Line Pipe

API Spec 15LE 15LE-1Polyethylene (PE) Line Pipe

API Spec 15LR 15LR-1Low Pressure Fiberglass Line Pipe

API Spec 15LT 15LT-1PVC Lined Steel Tubular Goods

API Spec 16A 16A-1Drill-Through Equipment

API Spec 16C 16C-1Choke and Kill Systems

API Spec 16D 16D-1Control Systems for Drilling Well Control Equipment

API Spec 17D 17D-1Subsea Wellhead and Christmas Tree Equipment

API Spec 17E 17E-1Subsea Production Control Umbilicals

API Spec 17J 17J-1Unbonded Flexible Pipe

API Spec 17K 17K-1Specification for Bonded Flexible Pipe

API Std 600 600-1Bolted Bonnet Steel Gate Valves for Petroleum and Natural Gas Industries Modified National Adoption of ISO 10434:1998

Please note that the following API Publications do notcontain Purchasing Guidelines:

API Spec 2F

API Spec 5B

API Spec 7F

API Spec 10A

API Spec 10D

API Spec 11AX

API Spec 11E

API Spec 11IW

API Spec 11V1

API Spec 13A

API Spec 16F

API Spec 16R

API Spec 17F

API RP 19B

API Spec 1581

API Spec 1583

Page No.

Installation Description:

Type of Installation: (Fixed Platform, TLP, Spar, Semi, Drillship)

Installation Main Deck Elevation above Sea Level: ft

Crane Boom Heel Pin Elevation above Main Deck: ft

Minimum Design Service Temperature: F

Maximum Design Service Temperature: F

Features

Boom Length: ft

Primer Mover:

Area Classification: (See Section 10.4)

At Crane: Class Division Group(s)

Boom: Class Division Group(s)

Power Unit: Class Division Group(s)

Out-of-service Maximum Conditions

Boom Not Stowed: Boom Stowed:

Max Wind mph Max Wind mph

For Floating Crane Vessel/Platforms:

Max Significant Sea (Hsig) ft Max Significant Sea (Hsig) ft

Max Crane Accelerations: Max Crane Accelerations:

Per Tables 3 5 for specified Hsig Per Tables 3 5 for specified Hsigg's horiz. and g's vert. g's horiz. and g's vert.

Performance Requirements

Ratings to be determined by which method (check one):

Vessel Specific Method (Floating Crane Vessels only)

General Method (Floating or Fixed Crane Installations)

Default Dynamic Method (Fixed Platforms onlycalm seas, tethered supply boat)

Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130 2C-1

American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to page 50 of API Spec 2CAPI Monogram Equipment Purchase API Spec 2C online at www.global.ihs.com

API Specification

2C Appendix CMinimum Purchaser-Defined RequirementsAPI Spec 2C

6th Edition, March 2004Specification for Offshore PedestalMounted Cranes

API Monogram Required Yes No

American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to page 50 of API Spec 2CAPI Monogram Equipment Purchase API Spec 2C online at www.global.ihs.com

API Specification 2C : 6th Edition, March 2004Specification for Offshore Pedestal Mounted Cranes

Appendix CMinimum Purchaser-Defined Requirements

Minimum Purchaser Defined Criteria for Fixed or Floating Installation

Purchaser Defined Onboard Lifts Onboard Lifts Offboard Lifts Offboard LiftsLift Criteria (Calm Seas) 2nd Criteria 1st Criteria 2nd Criteria

Main Block Required SWLlb.

Main Block SWL Radiusft

Auxiliary Required SWLlb.

Auxiliary Hook SWL Radiusft

Additional Criteria for Fixed/Bottom Supported or Floating/Vessel Installations


Main Block Speed @ Supply BoatDeckft/sec. n/a

Auxiliary Hook Speed @ Supply BoatDeckft/sec. n/a

Significant Wave Height (Hsig)ft n/a

Wind Speedmph

Additional Purchaser Defined CriteriaFloating/Vessel Installation Cranes Only(TLP/Spar/Semisubmersible/Drillship/Etc.)


Crane Base Static Inclination,(Installation List Angle)degrees

Crane Base Static Inclination,(Installation Trim Angle)degrees

Boom Tip Velocityft/sec. n/a

Horizontal Accelerationgs n/a

1g = 32.2 ft/sec.2

Copyright 2004 - American Petroleum Institute. All rights reserved. | 231302C-2

4Information to be Supplied by thePurchaser (See Note 1)4.1In placing orders for line pipe to be manufactured in accordancewith API Spec 5L, the purchaser should specify the following onthe purchase order:

Information Reference

Specification API Spec 5L

PSL (Product Specification Level) Par. 1.2 and Table 1

Quantity

Grade (and class, if applicable) Tables 2 and 3

Type of Pipe Par. 5.1.3

Size or Outside Diameter Par. 7.1

Wall Thickness Par. 7.1

Nominal Length Par. 7.5 and Table 11

End Finish Par. 7.9

Delivery Date and Shipping Instructions

4.2The purchaser should also state on the purchase order hisrequirements concerning the following stipulations, which areoptional with the purchaser:


Certificate of General Compliance Par. 12.1

Certificate of Compliance, Par. 12.1 and SR 15with Test Results

Cold Expanded or Par. 5.2Nonexpanded Pipe

High Carbon Equivalent Pipe Par. 6.1.3.2

Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130 5L-1

American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to pages 3 - 5 of API Spec 5LAPI Monogram Equipment Purchase API Spec 5L online at www.global.ihs.com

API Specification

5LInformation to be Supplied by thePurchaser

43rd Edition, March 2004Specification for Line Pipe


Optional Fracture Toughness: Par. 6.2.6; SR5;Test Type, Temperature, and SR6; SR19Charpy Energy Value

Acceptance and Maximum Par. 7.7Percent of Jointers

Jointers for Threaded Pipe Par. 7.7

Thread Compound Par. 7.9.2

Reduced Negative Tolerance Tables 9 and 10for Wall Thickness

Power-Tight Makeup Par. 7.9.2

Specific Edition of Spec 5L Par. 7.9.2for Pipe and Couplings

Alternative Bevel or End Par. 7.9.3Preparation, Plain-End Pipe

Alternative Minimum Hydrostatic Par. 9.4.3Test Pressure

Hydrostatic Test Pressure, Par. 9.4.3Maximum

Special Inspection of Electric Par. 9.7.2.2 and SR17Welded Seams

Alternative Inspection of Laser Par. 9.7.2.3 and SR17Welded Seams

Nondestructive Testing of Par. 9.7.2.6 and SR4Seamless Pipe

Type of Penetrameter for Par. 9.7.3.4Radiological Inspection

Bare Pipe; Temporary and Par. 11.1Special Coatings

Special Nondestructive Par. 7.8.10Inspection for Laminations

Demonstration of Capability of Par. 9.7.5.2Magnetic Particle Inspection Method

(Continued to next column) (Continued to next page)



API Specification 5L : 43rd Edition, March 2004Specification for Line Pipe

Information to be Supplied by the Purchaser


Through-the-Flowline (TFL) Pipe SR7

Length Tolerance and Jointer Par. SR7.2Allowance for TFL Pipe

Marking Requirements

Alternative Length Units Par. 10.5 and I.5

Additional Markings for Par. 10.1.3 and I.1.3Compatible Standards

Marking Location and Par. 10.2c and I.2.3Sequence for Welded Pipe, Size 16 and Larger

Die Stamping of Pipe or Plate Par. 10.7 and I.7

Method of Welding Jointers Par. A.1

Purchaser Inspection Par. 9.7.1 and Appendix H

Inspection Location Par. H.2

API Monogram Marking (see Note 2) Par. I.1

4.3The following stipulations are subject to agreement between thepurchaser and the manufacturer:


Alternative Heat Treatment Par. 5.1.3.3for Electric Weld Seams

Alternative Heat Treatment Par. 5.1.3.4for Laser Weld Seams

Quenching and Tempering Par. 5.4of Grade B Pipe

Skelp End Welds at Pipe Ends Par. 5.5

Chemical Composition Par. 6.1.1

Intermediate Grade Par. 6.1.1 and 6.2.1

Carbon Equivalent Limit (PSL 2)

Grade X80 Par. 6.1.3.2

Seamless with Wall Par. 6.1.3.2Thickness > 0.800 in (20.3 mm)

High Carbon Equivalent Pipe Par. 6.1.3.2


Charpy Specimen Size for Par. SR5.3Optional Fracture Toughness

Type of Notch for Drop Weight SR6.3Tear Test Specimens

Internal Diameter Tolerance Par. 7.2

Intermediate Diameter Par. 7.1

Intermediate Wall Thickness Par. 7.1

Skelp End Welds at Jointer Welds Par. 7.7

Hydrostatic Test for Threaded Par. 9.4.1and Coupled Pipe

Higher Hydrostatic Test Pressure Par. 9.4.3

End Load Compensation for Par. 9.4.3 andHydrotest Producing Stress Appendix K> 90% SMYS

Supplementary Hydrostatic Test Par. 9.4.4

Diameter Tolerance for Table 7Nonstandard Hydrotest

Alternative Nondestructive Test Par. 9.7.2.2Method for Seams at Ends of Electric Welded Pipe

Alternative Nondestructive Par. 9.7.2.3Test Method for Seams at Ends of Laser Welded Pipe

Alternative Penetrameter Par. 9.7.3.4for Radiological Inspection

Alternative Reinspection Method Par. 9.7.4.3for Gas-Metal-Arc Welds

Alternative Reference Standard Par. SR4.3.2for Nondestructive Inspection of Seamless

Technique for Nondestructive Par. SR17.2Inspection of Electric Welds and Laser Welds

Length Tolerances Applied Table 11to Carloads

Nonstandard Length and Par. 7.5Length Tolerances

(Continued to next column)

Copyright 2004 - American Petroleum Institute. All rights reserved. | 231305L-2


API Specification 5L : 43rd Edition, March 2004Specification for Line Pipe

Information to be Supplied by the Purchaser

Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130 5L-3



Welded Couplings Par. 8.1

NDT for Repair of Pipe Body Par. B.1.1by Welding

Repair of Weld Seams of Electric Par. 9.7.4.4 and B.1.2Welded Pipe

Repair of Weld Seams of Par. 9.7.4.4 and B.1.2Laser Welded Pipe

Repair of Heat-Treated Pipe Par. B.1.3by Welding

Reprocessing by Heat-Treatment Par. 9.11 and SR5.4

Disposition of Product Rejected Par. H.4by Purchaser

Marking Requirements

Marking of Couplings Without Par. 10.1.2 and I.1.2Die Stamping

Marking on Interior Instead of Par. 10.2b and I.2.2Exterior (Welded Pipe < Size 16, and Seamless Pipe)

Color Code Marking for Grade Par. 10.3.5 and I.3.5; SR3

Nonstandard Units of Length Par. 10.5 and I.5

Location for Length Markings Par. 10.5a and I.5a

Use of Cold Die Stamping Par. 10.7 and I.7

Notes:1. Nothing in this specification should be interpreted as indicating a preference by the committee for any material orprocess or as indicating equality between the various materialsor processes. In the selection of materials and processes, thepurchaser has to be guided by experience and by the service forwhich the pipe is intended.

2. Users of this specification should note that there is no longera requirement for marking a product with the API Monogram.The American Petroleum Institute continues to license use of themonogram on products covered by this specification, but it isadministered by the staff of the Institute separately from thespecification. The policy describing use of the monogram is contained in Appendix I. No other use of the monogram is permitted. Licensees mark products in accordance withAppendix I or Section 10, and nonlicensees mark products in accordance with Section 10.

A.1GeneralThis annex provides guidelines for enquiry and purchase of well-head and christmas tree equipment. These guidelines consist ofdata sheets to be completed by the purchaser, a series of typicalwellhead and christmas tree configurations, and a decision treefor determining product specification levels.

The data sheets are designed to perform two functions:

a) assist the purchaser in deciding what he wants;

b) assist the purchaser in communicating his particular needsand requirements, as well as information on the well environ-ment, to the manufacturer for his use in designing and pro-ducing equipment.

To use this Annex A, a copy of the data sheets should be com-pleted as accurately as possible. The typical configurationsshould be referred to, as needed, to select the required equip-ment. The decision tree Figure A.3, together with its instructions,provides the recommended practice as to which PSL each pieceof equipment should be manufactured. A copy of the data sheetshould then be attached to the purchase order or request for pro-posal.

A.2Data SheetsThe following pages contain questions and information that canbe used to select wellhead equipment, including chokes andactuators. Table A.2 contains general information which pertainsto the entire well. Tables A.3 to A.12 are designed to be used foreach type of equipment.

The effects of external loads (i.e. bending moments, tensions,etc.) on the assembly of components are not explicitly addressedby this International Standard (see 4.2.1.3). The purchasershould specify any exceptional loading configuration.

The purchaser should specify whether the performance verifica-tion procedures in Annex F are applicable.

A.3Typical Wellhead and Christmas TreeConfigurationsExamples of typical wellhead and christmas tree configurationsare shown in Figures A.1 and A.2. Also included are examples ofcasing and bit programmes that are consistent with the well-heads as shown.

A.4Product Specification Levels (PSL)A.4.1GeneralPSL 1 includes practices currently being implemented by a broadspectrum of the industry for service conditions recommended inthis Annex A.

PSL 2 includes all the requirements of PSL 1 plus additionalpractices currently being implemented by a broad spectrum ofthe industry for a specific range of service conditions asdescribed in this Annex A.

PSL 3 includes all the requirements of PSL 2 plus additionalpractices currently being implemented by a broad spectrum ofthe industry for a specific range of service conditions asdescribed in this Annex A.

PSL 3G includes all the requirements of PSL 3 plus additionalpractices currently being implemented by a broad spectrum ofthe industry for a specific range of service conditions asdescribed in this Annex A. The designation PSL 3G is only utilizedin those clauses and tables where necessary to define the addi-tional gas-testing requirements of equipment that can be gas-tested.

PSL 4 includes all the requirements of PSL 3G plus certain addi-tional requirements and is intended for applications that exceedthe service conditions usually identified within the scope of thisInternational Standard, and is normally only used for primaryequipment.

Figure A.3 shows the recommended specification level for pri-mary equipment. Primary equipment of a wellhead assemblyincludes as a minimum:

tubing head;

tubing hanger;

tubing head adapter;

lower master valve.

All other wellhead parts are classified as secondary. The specifi-cation level for secondary equipment may be the same as or lessthan the level for primary equipment.

The selection of PSL should be based on a quantitative riskanalysis which is a formal and systematic approach to identifyingpotentially hazardous events, and estimating the likelihood andconsequences to people, environment and resources, of acci-dents developing from these events.

The following comments apply to the basic questions asked inFigure A.3.


Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130 6A-1

American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to pages 215 233 of API Spec 6AAPI Monogram Equipment Purchase API Spec 6A online at www.global.ihs.com

API Specification

6A Annex A (informative)Purchasing Guidelines19th Edition, July 2004

Specification for Wellhead and ChristmasTree Equipment



API Specification 6A : 19th Edition, July 2004Specification for Wellhead and Christmas Tree Equipment

Annex A (informative)Purchasing Guidelines

A.4.2NACE MR 0175This applies if the partial pressure of hydrogen sulfide (H2S) inthe produced fluid equals or exceeds the minimum amount spec-ified by NACE MR 0175 for sour service.

A.4.3High H2S ConcentrationUse Yes if the H2S concentration of the produced fluid is suchthat in air an H2S concentration of 70 x 106 [70 parts per mil-lion (ppm)] can develop in case of a leak (human sense of smellcannot detect concentrations higher than 70 x 106).

Alternatively use Yes if the radius of exposure (ROE) to 100ppm H2S is greater than 15 m (50 ft) from the wellhead. ROE isdefined in Texas Railroad Commission Rule 36, see A.4.5. Othermethods of calculating ROE may apply depending on local regula-tions.

The above requires the knowledge of the adjusted open-flowrateof offset wells. If this is not available, but if hydrogen sulfide canbe expected, a 100 ppm ROE equal to 1,000 m (3,000 ft) may beassumed.

A.4.4Close ProximityUsers who are accustomed to the use of the close-proximity andradius-of-exposure concepts may substitute close proximity forgas well in Figure A.3.

The proximity assessment should consider the potential impactof an uncontrolled emission of H2S threatening life and environ-ment near the wellhead. The following list of items can be usedfor determining potential risk:

a) 100 ppm ROE of H2S is greater than 15 m (50 ft) from thewellhead and includes any part of a public area except a pub-lic road. ROE is defined in A.4.5. Public area means adwelling, place of business, place of worship, school, hospital,school bus stop, government building, a public road, all or anyportion of a park, city, town, village, or other similar area thatone can expect to be populated. Public road means any streetor road owned or maintained for public access or use;

b) 500 ppm ROE of H2S is greater than 15 m (50 ft) from thewellhead and includes any part of a public area including apublic road;

c) well is located in any environmentally sensitive area such as apark, wildlife preserve, city limits, etc.;

d) well is located within 46 m (150 ft) of an open flame or firedequipment;

e) well is located within 15 m (50 ft) of a public road;

f) well is located in or near inland navigable waters;

g) well is located in or near surface domestic water supplies;

h) well is located within 107 m (350 ft) of any dwelling.

These conditions are recommended minimum considerations.Any local regulatory requirements should be met.

A.4.5Radius of Exposure (ROE) of H2SA.4.5.1The following information is taken from Texas RailroadCommission Rule 36. SI metric-equivalent rules are not given, asthe method of ROE determination is used in the United Statesonly. Other methods of calculating ROE may apply depending onlocal regulations.

A.4.5.2For determining the location of the 100 ppm ROE:

X = [(1,589)(mole fraction H2S)(q)]0,625 8

For determining the location of the 500 ppm ROE:

X = [(0,454 6)(mole fraction H2S)(q)]0,625 8

where

X is the radius of exposure, in feet;

q is the maximum volume flowrate determined to be avail-able for escape, in cubic feet per day;

H2S is the mole fraction of hydrogen sulfide in the gaseousmixture available for escape.

A.4.5.3The volume flowrate used as the escape rate in determining theradius of exposure shall be that specified below, as applicable.

a) For new wells in developed areas, the escape rate shall bedetermined by using the current-adjusted open flowrate of off-set wells, or the field-average current-adjusted open flowrate,whichever is larger.

b) The escape rate used in determining the radius of exposureshall be corrected to standard conditions of 14.65 psia and60F (16C).

A.5Corrosivity of Retained FluidTo select the desired material class in Table 3, the purchasershould determine the corrosivity of the retained, produced orinjected fluid by considering the various environmental factorsand production variables listed in Table A.2. General corrosion,stress-corrosion cracking (SCC), erosion-corrosion, and sulfidestress cracking (SSC) are all influenced by the interaction of theenvironmental factors and the production variables. Other factorsand variables not listed in Table A.2 may also influence fluid cor-rosivity.

The purchaser should determine if materials shall meet NACEMR 0175 for sour service. NACE MR 0175 is only concerned withthe metallic material requirements to prevent sulfide stresscracking and not with resistance to general corrosion.Consideration should also be given to the carbon dioxide partialpressure, which generally relates to corrosivity in wells as shownin Table A.1. This table is a guideline only.

Analysis of produced fluids may not predict the field performanceof metallic or non-metallic material.

Copyright 2004 - American Petroleum Institute. All rights reserved. | 231306A-2


Partial Pressure of CO2





Retained Fluids

General Service

General Service

General Service

Sour Service

Sour Service

Sour Service

Table A.1 Relative Corrosivity of Retained Fluids as Indicated by CO2 Partial Pressure

(psia)

(30)

(30)

Relative Corrosivity

Non-corrosive

Slightly Corrosive

Moderately to Highly Corrosive

Non-corrosive

Slightly Corrosive

Moderately to Highly Corrosive

MPa

0.21

0.21

See following pages for Wellhead Equipment Data Sheets.

The minimum partial pressure of carbon dioxide required to initi-ate corrosion and the relative effect of increasing partial pres-sures on the corrosion rate are strongly influenced by other envi-ronmental factors and production variables, such as:

a) temperature;

b) H2S level;

c) pH;

d) chloride ion concentration;

e) sand production;

f) water production and composition;

g) types and relative amounts of produced hydrocarbons.

Finally, the purchaser should consider future service of the wellwhen selecting a material class. This should not be limited toanticipated changes in the acid gas partial pressures for produc-tion or increased water production with or without increasedchloride content, but also should include consideration of opera-tions such as acidification or other well treatments.

Well Name(s) and Location(s)

Maximum Operating Pressure

Anticipated Wellhead Shut-In Pressure

Temperature Ranges Anticipated

Minimum Ambient Temperature

Maximum Flowing Fluid Temperature at Wellhead

Anticipated Composition of Produced Fluids

CO2 (mg) H2S (mg)

Chlorides (mg) Other

Anticipated Completion or Future Workover or Recovery Operations which would Affect Pressure, Temperature, or Fluid Content

New Values

Are there any Government Regulations that will apply or must be met by this equipment Yes No If so, Which One(s)

Water or Brine pH

Does NACE MR 0175 Apply Yes No Will Scale, Paraffin, Corrosion, or Other Types of Inhibitors be Used Yes No

Inhibitor Type

Inhibitor Carrier

Batch or Continuous Inhibition

Will Acidification be Performed Yes NoType of Acid

Anticipated Production Rates m3/d Oil/Condensate

m3/d Gas

m3/d S&Wa

Will Erosion be a Concern Yes NoCause

External Coating Yes NoType

Internal Coating Yes NoType

Delivery Requirements

Special Shipping, Packing and Storage Instructions

aSand and Water.




Table A.2 Wellhead Equipment Data SheetGeneral






Table A.2 Wellhead Equipment Data SheetGeneral (continued)

Casing Program

Conductor

Surface Csg.

Protective Csg.

Production Csg.

Tubing

Type of Completion Single Multiple

Size (OD)Bit Sizemm (in.)

Total String Hanging Wt.

daN (lbs)Gradekg/m(lb/ft) Connection

Top Joint in String




Bottom Connection Size

Rated Working Pressure

Type

Top Connection Size


Type

Outlets Size


Type

Number

Equipment for Outlets Valve-removal Plug

Valves (Inboard) Qty PSL PR

Valves (Other) Qty PSL PR

Companion Flanges Qty PSL

Bullplugs Qty

Nipples Qty

Needle Valves Qty

Gauges Qty

Lock Screws Yes NoLock Screw Function

Base Plate Requirements

Special Material Requirements

Casing Hanger

Size

Type

PSL

PR

Temperature Rating (Table 2)

Material Class (Table 3)

Retained Fluid Corrosivity (Table A.1)

Witness Yesa NoExternal Coating Yes No

Type


Flange Bolting Requirements (Table 49) Non-exposed Exposed Exposed (Low Strength)

Main Run (Studs) (Nuts)

Outlet Inboard (Studs) (Nuts)

Outlet Other (Studs) (Nuts)

Test and Auxiliary Equipment

Wear Bushing

Running and Retrieving Tools

Test Plug

Other Requirements

aIf yes, specify what and by whom.

Table A.3 Wellhead Equipment Data SheetCasing-head Housing

Casing Head Housing PSL PR








Type

Top Connection Size


Type

Outlets Size


Type

Number

Equipment for Outlets Valve-removal plug




Bullplugs Qty

Needle Valves Qty

Gauges Qty



Bottom Casing Spool Pack-off size

Type

PR

Casing Hanger

Size

Type

PSL

PR





Type


Flange Bolting Requirements (Table 49) Non-exposed Exposed

Outlet inboard (Studs) (Nuts)

Outlet other (Studs) (Nuts)


Wear Bushing


Test Plugs

Other Requirements


Table A.4 Wellhead Equipment Data SheetCasing-head Spool

Casing-head Spool PSL PR



Appendix APurchasing Guidelines



Type

Top Connection Size


Type

Outlets Size


Type

Number

Equipment for Outlets Valve Removal Plug




Bullplugs Qty

Nipples Qty

Needle Valves Qty

Gauges Qty


Material Requirements

Bottom Tubing Spool Pack-off

Size

Type

PR

Tubing Hanger

Size

Type

PSL

PR

Back-pressure Valve Type

Surface-controlled Subsurface Valve Control Lines


Table A.5 Wellhead Equipment Data SheetTubing-head Spool

Tubing-head Spool PSL PR








Type







Wear Bushing


Test Plug

Other Requirements




Table A.5 Wellhead Equipment Data SheetTubing-head Spool (continued)





Table A.6 Wellhead Equipment Data SheetCross-over Flange

Cross-over Flange PSL PR



Type

Top Connection Size


Type

Pack-off Type

Size





Type








Table A.7 Wellhead Equipment Data SheetTubing Head Adaptor



Type

Top Connection Size


Type

Surface-Controlled Subsurface Safety Valve Outlets

Number

Size

Electrical Feed-through Connection






Type






Tubing Head Adaptor PSL PR


Lower Master Value

Upper Master Value

Swab (Crown) Valve

Wing ValveInboard

Wing Valve(s)Other

Tee/Cross (Circle one)

Choke

End Flange

Companion Flanges

Instrument Flanges

Tree Cap/Top Connection





Upper Master Prepared for Actuator Yes NoIf yes, specify class I or II below PR column

Wing ValveInboard Prepared for Actuator Yes NoIf yes, specify class I or II below PR column

Wing ValveOther Prepared for Actuator Yes NoIf yes, specify class I or II below PR column

Choke (Adjustable or Fixed)

Orifice Size

Nominal Size

Pressure Drop

Flowline Connection

Size

Type



Table A.8 Wellhead Equipment Data SheetChristmas Tree and Choke

Christmas Tree and Choke Single Solid Block Dual Stacked

Size Materiala PSL PR Witness?b

ExternalCoating? IfYes, State

Type

FlangedBolting

RequirementscStud Nuts

RingGasket

Type

a Define or specify material requirements and, if cladding or other corrosion resistant materials are to be inlayed, state base material type/clad material type, e.g., 4130/625.

b If yes, specify what and by whom.

c Indicate required bolting for the applicable retained fluid and temperature classification specified in Table 49.






Other Requirements

Upper Master Valve Type Actuator Requirements

Pneumatic/Piston Hydraulic/Piston Electric

Supply Pressure/Power

Pneumatic/Diaphragm Hydraulic/Diaphragm Electric

Air Gas

Wing Valve Type Actuator Requirements

Pneumatic/Piston Hydraulic/Piston Electric

Pneumatic/Diaphragm Hydraulic/Diaphragm Electric

Supply Pressure

Other



Table A.8 Wellhead Equipment Data SheetChristmas Tree and Choke (continued)




Table A.9 Wellhead Equipment Data SheetCompact Casing Head-housing


A. Bottom Connection Size


Type

Outlets Size


Type

Number





Bullplugs Qty

Nipples Qty

Needle Valves Qty

Gauges Qty


Base Plate Requirements

Witness Yesa NoBottom Casing Spool Pack-off

Size

Type

Casing Hanger

Size

Type

PSL

PR






Flange Bolting Requirements (Table 49)



Other Requirements

a If yes, specify what and by whom.

Compact Casing Head-housing PSL PR


American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to pages A-1 A-14 of API Spec 6AAPI Monogram Equipment Purchase API Spec 6A online at www.global.ihs.com




B. Top Connection Size


Type

Outlets Size


Type

Number





Bullplugs Qty

Nipples Qty

Needle Valves Qty

Gauges Qty



Casing Hanger

Size

Type

PSL

PR






Flange Bolting Requirements (Taable 49)



Test and Auxiliary Equipment (Top and/or Bottom)

Wear Bushings


Test Plugs

Other Requirements


Table A.9 Wellhead Equipment Data SheetCompact Casing Head-housing (continued)



Table A.10 Wellhead Equipment Data SheetWellhead Safety Valves

Wellhead Safety Valves


General

Special Environmental Conditions Unusual ambient or operating temperatures, or atmospheric conditions conducive to corrosion or underwater use

Coating

Shipping Instructions

SSV/USV Valve

Performance Test Agency (PR 2 SSV/USV Valves)

Manufacturer Model and Type

Size


Temperature Range

SSV/USV Actuator

Manufacturer Model and Type

Cylinder Rated Working Pressure

Operating Pressure Purchaser should specify available supply pressure, if applicable

Temperature Range

Lock Open Device

USV Working Water Depth





Table A.11 Wellhead Equipment Data SheetChoke Sizing


Application

Fluid

Quantity

End Connections/A&B Dimensionsa

Pressure Rating/Inlet Outlet

Temperature Rating

Material Class Body Trim

PSL PR

Service Conditions at Max. Flow (Units) Normal Flow (Units) Min. Flow (Units)

Pressure Inlet

Outlet or PTemperature at Inlet

Oil Flowrate

S.G. (if available)

Gas Flowrate

or G.O.R.

S.G. (if available)

Liquid Flowrate

S.G. (if available)

Manual/Actuated

Actuator Type/Make/Model

Power Source

Manual Override

Position Indication Local Remote/Position Transmitter

Positioner

Additional Comments

a See Figures 20 and 21.



Table A.12 Wellhead Equipment Data SheetActuator and Bonnet


Quantity Quantity QuantityPneumatic Hydraulic ElectricDiaphragm Single Conventional Rising Stem

Double Non-rising StemRetained fluid Rising Stem

Piston Single Non-rising StemDouble Wirecutter Wire/Cable Size

Self-contained Stand-alone Power Source

Supply Requirements/SpecificationsPneumatic HydraulicAvailability MPa (psi) Availability MPa (psi)

Max. Min. Max. Min.Clean Air Well FluidNitrogen Non-NACE NACEWell Gas Non-NACE Self-containedOther NACE Other

ElectricVoltageDC AC Phase FrequencyCurrent AvailableOther

Actuator Requirements Field DataSpecifications Actuator CustomerTemperature Rating (Table 2) Field LocationRetained Fluid (Table A.1) PlatformMaterials Class (Table 3) Well No.External Coating? No Yes Closed-in Tubing Head Pressure MPa (psi)

If yes typeAccessoriesFusible Hold-open DeviceManual Hold-open DeviceQuick Exhaust ValvePosition Indication a) Local

b) Remote

Bonnet RequirementsSize Specification PSLModel SSV PR2 2Maximum Working Pressure MPa (psi) 3

3G4

Material Class: Temperature Rating:


Option 1

5,000 psi (34,5 MPa) WP

Option 2

Option 3

Surface SafetyValve

Option 4

Surface SafetyValve

Option 5

(or 5,000 psi [34,5 MPa])

3,000 psi (20.7 MPa)



Casing Programin. (mm)

858 (219.1) x 512 (139.7)

958 (244.5) x 7 (177.8)

1034 (273.1) x 758 (193.7)

Casing Head Top Flangein. psi (mm MPa)

11 3000 (279 20.7)

or

11 5000 (279 34.5)

Tubing Head Top Flangein. psi (mm MPa)

7116 5000 (179 34.5)

Bit Programin. (mm)

778 (200.0)

812 (215.9) or 834 (222.2)

978 (250.8)

Typical Programs


Figure A.1 Typical Wellhead and Tree Configuration 5,000 psi (34.5 MPa) Rated Working Pressure (WP)


5,000 psi (34.5 MPa) WP

3,000 psi (20.7 MPa)

(OR 5,000 psi [34.5 MPa])

Surface SafetyValve

Option 4

Surface SafetyValve

Option 5

Option 1

Option 2

Option 3

Option 1

10,000 psi (69,0 MPa) WP

10,000 psi (69,0 MPa)

5,000 psi (34,5 MPa)

Option 2

Option 3

Surface SafetyValve

Option 4

Surface SafetyValve

Option 5

Casing Back Pressure Control

ValveOption 6



Figure A.2 Typical Wellhead and Tree Configuration 10,000 psi (69.0 MPa) Rated Working Pressure (WP)


Casing Program (in.)

16 x 1034 x 758

16 x 1134 x 958 7 Liner

1338 x 958 x 7

1034 x 758 x 5

Casing Head HousingTop Flange(in. psi)

1634 5000

1634 5000

1358 5000

16 5000

Casing Head SpoolTop Flange(in. psi)

11 10,000

1358 10,000

11 10,000

11 10,000

11 10,000

Bit Program (in.)

1434 x 978 or x 912

1434 x 1058 x 812

1214 x 812 x 6

978 x 612

Typical Programs (US Customary Units)

Typical Programs (Metric)


Tubing HeadTop Flange(in. psi)

7116 10,000

7116 10,000

7116 10,000

7116 10,000

Casing Program (mm)

406.4 x 273.1 x 193.7

406.4 x 298.5 x 244.5 x 177.8Liner

339.7 x 244.5 x 177.8

273.1 x 193.7 x 127.0

Casing Head HousingTop Flange

(mm MPa)

425 34.5

425 34.5

346 34.5

279 34.5

Casing Head SpoolTop Flange

(mm MPa)

279 69.0

346 69.0

279 69.0

279 69.0

279 69.0

Bit Program (mm)

374.7 x 250.8 or 241.3

374.7 x 269.9 x 215.9

311.2 x 215.9 x 152.4

250.8 x 165.1

Tubing HeadTop Flange

(mm MPa)

179 69.0

179 69.0

279 69.0

179 69.0

Option 2

Option 1

Option 3

Surface SafetyValve

Option 4

10,000 psi (69.0 MPa)

CasingBack PressureControl Valve

Option 6

10,000 psi (69.0 MPa) WP

Surface SafetyValve

Option 5

5,000 psi (34.5 MPa)



Figure A.3 Recommended Minimum PSL for Primary Parts of Wellheads and Christmas Tree Equipment




15,000 psi (103.5 MPa)

Start Here

NACE MR 0175?

High H2SConcentration?

Gas Well?

Rated WorkingPressure

Rated WorkingPressure Gas Well?

Gas Well?

High H2SConcentration?

Gas Well? Rated WorkingPressure

Rated WorkingPressure

No

Yes Yes

No

Yes

YesYes Yes

No

No

No

No

No

Yes

Yes

5,000 psi(34.5 MPa)

No

>5,000 psi (34.5 MPa)

5,000 psi(34.5 MPa)

>5,000 psi (34.5 MPa)

5,000 psi (34.5 MPa)

>5,000 psi (34.5 MPa)

5,000 psi (34.5 MPa)>5,000 psi (34.5 MPa)

PSL 3G

PSL 3G

PSL 3

PSL 3G

PSL 3

PSL 2

PSL 3

PSL 2

PSL 2

PSL 1

PSL 3

PSL 2

PSL 1

American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to page 43 44 of API Spec 7KAPI Monogram Equipment Purchase API Spec 7K online at www.global.ihs.com

API Specification

7K3rd Edition, September 2002Specification for Drilling and Well Servicing EquipmentAddendum 1, September 2002 and Addendum 2, April 2004

Appendix B

Supplementary Requirements

Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130 7K-1

B.0 IntroductionBy agreement between the purchaser and manufacturer, andwhen specified in the purchase order, one or more of thefollowing supplementary requirements shall apply.

B.1SR1Proof Load TestingThe equipment shall be load tested and subsequently examinedin accordance with the requirements of 8.6 of this specification.

The equipment shall be marked SR1 by means of low-stresshard-die stamping near the Load Rating identification.

B.2SR2Low Temperature TestingUnder this supplementary requirement, the maximum impact testtemperature for materials used in primary load carryingcomponents of covered equipment with a required minimumoperating temperature below that specified in 4.1 shall bespecified by the purchaser.

Impact testing shall be performed in accordance with therequirements of 6.3 of this Specification and ASTM A370. Exceptfor manual tong hinge pins of wrought material, the minimumaverage Charpy impact energy of three full size test pieces shallbe 20 ft-lb (27 J) with no individual value less than 15 ft-lb (20 J).For manual tong hinge pins of wrought material, the minimumaverage impact energy of three full size Charpy impact testpieces shall be 11 ft-lb (15 J) with no individual value less than8.5 ft-lb (12 J).

Each primary load bearing component shall be marked SR2 toindicate that low temperature testing has been performed. Eachprimary load bearing component shall also be marked with thetemperature in degrees Celsius to indicate the actual design andtest temperature.

B.3SR2AAdditional Low Temperature TestingUnder this supplementary requirement, impact testing shall alsobe applicable to materials used in the primary load carryingcomponents of equipment normally exempted from impacttesting. The components to which impact testing shall apply shallbe determined by mutual agreement of the purchaser and themanufacturer.

Impact testing shall be performed in accordance with therequirements of 6.3 of this Specification and ASTM A370. Themaximum impact test temperature and the minimum averageand individual values shall be as agreed upon by the purchaserand the manufacturer.

Each covered primary load carrying component shall be markedSR2A to indicate that additional low temperature testing hasbeen performed. The component shall also be marked with thetemperature in degrees Celsius to indicate the actual design andtest temperature.

B.4SR3Data BookWhen requested by the purchaser, records shall be prepared,gathered, and properly collated in a data book by the manufacturer.

The data book shall at least include for each unit:

Statement of Compliance

Equipment Designation/Serial Number

Assembly and Critical Area Drawings

Nominal Capacities and Ratings

List of Components

Traceability Codes and Systems (marking on parts/recordson file)

Steel Grades

Heat Treatment Records

Material Test Reports

NDE Records

Performance Test Records including Functional Hydrostaticand Load Testing Certificates (when applicable)

Supplementary Requirements Certificates as Required

Welding Procedure Specifications and Qualification Records

B.5SR4Additional Volumetric Examination ofCastingsThe requirements for SR4 shall be identical to the requirementsfor 8.4.7, except that all critical areas of each primary loadbearing casting shall be examined.

B.6SR5Volumetric Examination of WroughtMaterialThe entire volume of primary load bearing wrought componentsshall be examined by the ultrasonic method. When examinationof the entire volume is impossible due to geometric factors,such as radii at section changes, the maximum practical volumeshall suffice.


API Specification 7K : 3rd Edition, September 2002Specification for Drilling and Well Servicing EquipmentAddendum 1, September 2002 and Addendum 2, April 2004

Appendix BSupplementary Requirements

7K-2 Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130

American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to page 43 44 of API Spec 7KAPI Monogram Equipment Purchase API Spec 7K online at www.global.ihs.com

Ultrasonic examination shall be in accordance with ASTM A 388(the immersion method may be used) and ASTM E 428. Straight-beam calibration shall be performed using a distance-amplitudecurve based on a flat-bottomed hole with a diameter of 3.2 mmor smaller.

Wrought components examined by the ultrasonic method shallmeet the following acceptance criteria:

a. for both straight and angle beam examination, anydiscontinuity resulting in an indication which exceeds thecalibration reference line is not allowed. Any indicationinterpreted as a crack or thermal rupture is also not allowed;

b. multiple indications (i.e. two or more indications), eachexceeding 50% of the reference distance amplitude curve andlocated within 13 mm of one another, are not allowed.

American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to page 55 of API Spec 9AAPI Monogram Equipment Purchase API Spec 9A online at www.global.ihs.com

API Specification

9A25th Edition, February 2004Specification for Wire Rope

ISO 10425:2003 Steel wire ropes for thepetroleum and natural gas industries Minimumrequirements and terms for acceptance

Annex K (informative)Information with Enquiry or Order


The following information should be provided by the purchaserwhen making an enquiry or placing an order:

a) reference to this International Standard;

b) quantity and length;

c) nominal diameter;

d) rope class or construction;

e) core type;

f) rope grade;

g) wire finish;

h) lay direction and type;

i) preformation;

j) lubrication;

k) any particular marking requirements;

l) any particular packing requirements;

m) minimum breaking force required.


American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to page 99 of API Spec 16AAPI Monogram Equipment Purchase API Spec 16A online at www.global.ihs.com

API Specification

16A3rd Edition, June 2004Specification for Drill-Through Equipment

Appendix E (informative)

Purchasing Guidelines


E.1GeneralThis annex provides recommended guidelines for enquiry andpurchase of equipment covered by the scope of ISO 13533.

E.2Blowout Preventers and Drilling SpoolsE.2.1Size DesignationThe size designation consists of the vertical through-boredimension. A list of standard sizes is included in Table 1.

E.2.2Service ConditionsE.2.2.1Rated Working PressureThe rated working pressure is determined by the lowest pressurerating of all integral end or outlet connections. Rated workingpressures for equipment covered by the scope of ISO 13533 aregiven in 5.2.1.

E.2.2.2Temperature RatingsE.2.2.2.1GeneralMinimum temperature is the lowest ambient temperature towhich the equipment may be subjected. Maximum temperatureis the highest temperature of the fluid that may flow through theequipment.

E.2.2.2.2Metallic MaterialsMetallic parts will be designed to operate in one of threetemperature ratings, which should be designated by thepurchaser. These ratings can be found in Table 3.

E.2.2.2.3 Wellbore Elastomeric MaterialsThe purchaser should provide the temperature range for whichwellbore elastomeric materials must operate.

E.2.2.2.4All Other Elastomeric SealsThe purchaser should provide the temperature range for which allother elastomeric materials must operate.

E.2.3Outlet ConnectionsThe purchaser should determine the number, location, size,pressure and temperature ratings for all outlet connections. Itshould be noted that the pressure rating for the BOP or drillingspool is determined by the lowest pressure rating of all end oroutlet connections.

E.2.4Equipment Details/Data BookA data book should be supplied upon the request of thepurchaser, and should contain the following information:

a) purchase order number/sales order number;

b) product identification, type, part number, serial number;

c) date of completion and inspection;

d) assembly drawings, actual overall package dimensions,pressure rating, end connection/outlet description, mass,centre of gravity, list of materials for components defined in8.5.1 and the location of their use;

e) manufacturer's statement of compliance to current edition ofISO 13533;

f) material certificates;

g) welding procedure qualification;

h) NDE reports;

i) pressure test reports.


American Petroleum Institute Handbook Revision 09.18.04Purchasing Guidelines Handbook Refer to pages 57 - 63 of API Spec 16DAPI Monogram Equipment Purchase API Spec 16D online at www.global.ihs.com

API Specification

16D2nd Edition, July 2004Specification for Control Systems for Drilling Well ControlEquipment and Control Systems for Diverter Equipment

Annexes A and B

Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130 16D-1

Annex A (informative)Table A-1 Control System Control System Operating and Interface Requirements for Surface BOP Stack

Regulatory Agency Compliance Required Yes NoRegulatory Agency(s) MMS HSE NPD OtherBOP Stack Size Working Pressure

BOP Stack Rams Annular (BOPs) Valves

Valves Failsafe Open Failsafe Close

Annular BOP Quantity Size Working Pressure

Manufacturer Model

RAM BOPs Quantity Size Working Pressure

RAM Locks Yes No TypePipe Rams Closing Ratio

Shear Ram Operating Pressure Size Type Grade

Shear Rams Closing Ratio Pipe to Shear Shearing Pressure

Manufacturer Model

Choke Valve(s) Required Size Working Pressure

Operating Pressure (Against Working Pressure) Open CloseManufacturer Model

Kill Valve(s) Quantity Size Working Pressure

Operating Pressure (Against Working Pressure) Open CloseManufacturer Model

Hydraulic Pump Systems

Electric Powered Quantity Size Working Pressure

Electricity Available: V A Type Grade

Air Powered Quantity Size Working Pressure

Air Pressure CFM

Remote Panel(s) Quantity Area Classification

Location of Choke Connection(s) (To Show on Panel Graphic)

Location of Kill Connection(s) (To Show on Panel Graphic)


API Specification 16D : 2nd Edition, July 2004Specification for Control Systems for Drilling Well ControlEquipment and Control Systems for Diverter Equipment

Annexes A and B

16D-2 Copyright 2004 - American Petroleum Institute. All rights reserved. | 23130

Table A-2 Surface Stack Hydraulic Control System Control Function List(Select as Applicable)

Closing 2 Pos.No. Control Function Ratio Gallons Required

1. Annular BOP Open Close N/A

2. Upper Pipe RAMS Open Close

3. Middle Pipe RAMS Open Close

4. Lower Pipe RAMS Open Close

5. Choke Valve Open Close N/A

6. Kill Valve Open Close N/A

Table A-3 Diverter System Hydraulic Control System Control Function List(Select as Applicable)

Diverter Model

Gallons 2 Pos.No. Control Function Required Operating Pressure

Max Min

1. Diverter Unit Open Close

2. Flow Selector Port Starboard

3. Vent Valve Open Close

4. Port Overboard Valve Open Close

5. Starboard Overboard Valve Open Close

6. Flowline Valve Open Close

7. Diverter Lockdown Dogs Latch Unlatch

8. Insert Packer Lockdown Dogs Latch Unlatch

9. Flowline Seal Energize Vent

10. Filling Line Valve Open Close

11. Overshot Packer Seal Energize Vent

12. Other (Specify) (Specify) (Specify)

Note which functions (if any) are to be interconnected for sequencing.





Annex BTable B-1 Control Operating and Interface Requirements Subsea BOP Stack

Regulatory Agency Compliance Required Yes NoRegulatory Agency(s) MMS HSE NPD OtherControl System Type Hydraulic EH MUXMaximum Water Depth Hydraulic Operating Pressure

BOP Stack Size Working Pressure

BOP Stack Ram Annular BOPs Failsafe Valves

Valves are FSO FSC FAO FACSubsea Umbilicals

Manufacturer Model Length

Subsea Hydraulic Supply Lines

Umbilical Hose Quantity & Length Size Working pressure

Supply Hose Quantity & Length Size Working pressure

Hydraulic Conduit Quantity & Length Size Working pressure

Annular BOP(s) Quantity Size Working pressure

Manufacturer Model

Shear Ram BOP(s) Quantity Size Working pressure

Shear Ram Locks Yes No TypeClosing Ratio Pipe Size and Grade Shear Pressure for Specified Pipe (Surface)

Ram BOP(s) Quantity Size Working pressure

Ram Locks Yes No TypeClosing Ratio

Manufacturer Model

Riser Connector Size Working Pressure

Manufacturer Model

Wellhead Connector Size Working Pressure

Manufacturer Model

Choke Valve(s) Quantity Size Working pressure

Manufacturer Model

Choke Outlet Location(s)


Annexes A and B




Kill Valve(s) Quantity Size Working pressure

Manufacturer Model

Kill Outlet Location(s)

LMRP Accumulators Quantity Size Working pressure Banks

BOP Accumulators Quantity Size Working pressure Banks

Hydraulic Pump Systems

Electric Powered Quantity Size Working pressure

Electricity Available: V A Hz Phase

Air Powered Quantity Size Working pressure

Air Pressure Required Air Volume Required

Remote Panels

Hazardous Location Quantity Area Classification

Safe Location Quantity

Table B-2 Subsea Stack Hydraulic Control System Control Function List(Select as Applicable)

No. Control Function Gallons Control PosPressure

1. POD Select Blue Yellow 3

2. Upper Annular BOP Open Close 3

3. Lower Annular BOP Open Close 3

4. Riser Connector Unlock Lock 3

5. Riser Connector Secondary Unlock Vent 2

6. Upper Pipe Rams Open Close 3

7. Shear Rams Open Close 3

8. High Pressure Shear Rams Close 1

9. Upper Pipe Rams Open Close 3

10. Middle Pipe Rams Open Close 3

11. Lower Pipe Rams Open Close 3

12. Wellhead Connector Unlock Lock 3

13. Wellhead Connector Secondary Unlock Vent 2

14. POD Latch Latch Unlatch 2

15. Blue Hydraulic Stabs Extend Retract 3

16. Yellow Hydraulic Stabs Extend Retract 3

17. Choke and Kill Stabs Extend Retract 3

18. Annular BOP Outer Bleed Open Close 2

19. Annular BOP Inner Bleed Open Close 2

20. LMRP Choke and Kill Test Valve Close Open 2

21. Upper Outer Choke Open Close 2

22. Upper Inner Choke Open Close 2

23. Lower Outer Choke Open Close 2


Annexes A and B




Table B-2 Subsea Stack Hydraulic Control System Control Function List (continued)(Select as Applicable)

No. Control Function Gallons Control PosPressure

24. Lower Inner Choke Open Close 2

25. Upper Outer Kill Open Close 2

26. Upper Inner Kill Open Close 2

27. Lower Outer Kill Open Close 2

28. Lower Inner Kill Open Close 2

29. Shear Rams Locks Lock Unlock 2

30. Upper Rams Locks Lock Unlock 2

31. Upper Middle Rams Wedgelocks Lock Unlock 2

32. Lower Middle Rams Wedgelocks Lock Unlock 2

33. Lower Rams Locks Lock Unlock 2

34. Blue Supply Pilot Check Vent Check 2

35. Yellow Supply Pilot Check Vent Check 2

36. LMRP Accum Isolator Open Close 2

LRMP Accum Dump Open Close 2

37. Lower Stack Accum Isolator Open Close 2

Lower Stack Accum Dump Open Close 2

38. LMRP Failsafe Supply Open Close 2

39. Lower Stack Failsafe Supply Open Close 2

40. Acoustic Accum Isolator Open Close 2

Acoustic Accum Dump Open Close 2

41. Subsea Mainfold Regulator Increase Decrease 2

42. Failsafe Assist Regulator Increase Decrease 2

43. Upper Annular BOP Regulator Increase Decrease 2

44. Lower Annular BOP Regulator Increase Decrease 2

Hose Reel Live Functions1.2.3.

Acoustic Functions1.2.3.4.

ROV Functions1.2.3.4.

Annexes A and B


Table B-3 Subsea Stack Hydraulic Control System Readback Function List (Select as Applicable)

No. Redback Function Required

1. Surface Accumulator Supply Pressure

2. Surface Pilot Supply Pressure

3. Rig Air Supply Pressure

4. Subsea Manifold Regulator Pilot Pressure

5. Subsea Manifold Regulated Pressure

6. Failsafe Assist Regulator Pilot Pressure

7. Failsafe Assist Regulated Pressure

8. Upper Annular BOP Regulator Pilot Pressure

9. Upper Annular BOP Regulated Pressure

10. Lower Annular BOP Regulator Pilot Pressure

11. Lower Annular BOP Regulated Pressure

Table B-4 Surface Diverter Hydraulic Control System Control Function List (Select as Applicable)

No. Control Function 2 Pos

1. Diverter Unit Open Close

2. Flow Selector Port Starboard

3. Diverter Lockdown Latch Unlatch

4. Vent Valve Open Close

5. Port Overboard Valve Open Close

6. Starboard Overboard Valve Open Close

7. Flowline Valve Open Close

8. Insert Packer Lockdown Dogs Latch Unlatch

9. Flowline Seal Energize Vent

10. Filling Line Valve Open Close

11. Ball Joint Pressure Range

12. Overshop Packer Energize Vent

13. Trip Tank Open Close

14. Support Ring Open Close

15. Other (Specify)

Note which functions (if any) are to be interconnected for sequencing.



Annexes A and B

Table of ContentsSpec 2CSpec 5LSpec 6ASpec 7KSpec 9ASpec 16ASpec 16D

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