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  • 1. A P I RP*I(/4E 91 m 0732290 0099482 5 Recommended Practice for Design and Installationof Offshore Production Platform Piping Systems API RECOMMENDED PRACTICE 14E (RP 14E) FIFTH EDITION, OCTOBER 1,1991 American Petroleum Institute 1220 L Street, Northwest Washington, DC 20005COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 2. A P I R P * 1 4 E 91 I 0732290 0099483 7 I Issued by AMERICAN PETROLEUM INSTITUTE Production Department FOR INFORMATION CONCERNING TECHNICAL CONTENTS OF THIS PUBLICATION CONTACT THE API PRODUCTION DEPARTMENT, 1201 MALN STREET,SUITE 2535, DALLAS, TX 75202-3904 - (214) 748-3841. SEE BACK COVER FOR INFORMATION CONCERNING HOW TO OBTAIN ADDITIONAL COPIES OF THIS PUBLICATION. Users of this publication shouldbecome completely familiar with itsscope and content. This publication is intended to supplement rather than replace individual engineering judgment. OFFICIAL PUBLICATION REG. US. PATENT OFFICE Copyright Q 1991 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 3. A P I RP*KL4E 91 W 0732290 0 0 9 9 4 8 4 9 W 2 Institute Petroleum American API RECOMMENDED PRACTICE FOR DESIGN AND INSTALLATION OFOFFSHOREPRODUCTIONPLATFORMPIPINGSYSTEMS TABLE OF CONTENTS Page POLICY 6 FOREWORD 7 DEFINITIONS 7 SYMBOLS 8 - SECTION 1 GENERAL 9 Scope _._____.___.__._________________ .. 9 Piping for Pressure Code 9 Policy 9 Industry Codes, Standards Guides and 9 Steel and .Iron American Institute 9 National American Institute Standards 9 Institute Petroleum American 10 American Society for Testing Materials and ____ 10 American Society of Mechanical Engineers 10 10 National Association ?f Corrosion Engineers-_.________------.-------------- Protection National Fire Association 10 Gas Processors Suppliers Association __________.__.____ 10Institute Hydraulics 10 Rules Governmental Regulationsand lo Demarcation Between Systems with Different Pressure Ratings--.-- 11 Corrosion 13 General 13 Weight Loss 13 Sulfide Stress .. Chloride Stress Cracking, e . 13 13 Appllcatlon of NACE MR-01-75 13 14 - SECTION 2 PIPING DESIGN Pipe 14 Non-Corrosive Hydrocarbon Service 14 Hydrocarbon Corrosive 14 .. . Sulfide Stress Cracking 14 Service Utilities ____.__I 14 Tubing 14 Sizing Criteria - . . . .. . . 14 Slang Criteria for Liquid 15 General . . 15 Pump 15 Sizing Criteria for Single-phase Gas 21 Equation Drop Pressure General e . 21 Drop Pressure Empirical 21 .. Gas Velocity Equation 22 Compressor Plpmg 23 General Notes r_______________________________________--23 Sizing Criteria for Gas/Liquid Two-Phase Lines 23 .. Erosional Velocity 23 Minimum Velocity 23 Pressure 23 Pipe Wall Thicknesses 25 Joint Connections . .. 25 and Expansion Start-up .. 25 25 References 26COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 4. API R P S l 4 E 91 W 0732290 0 0 9 9 4 8 5 O W RP 14E: Offshore Production Platform Piping Systems 3 TABLE OFCONTENTS (Continued) Page SECTION 3 -SELECTION OF VAL VES__-_.____------^.-..-.--.-- 29 General 29 ____.._.____c.._________________________~..---.-_.-- Types of Valves 29 Ball Valves_..._..____.._._____________________ 29 Gate Valves 29 Plug Valves 29 Butterfly Valves 29 Globe Valves 29 (Bladder) Diaphragm Valves __ 29 Needle Valves 30 Valve * . Check Valves 30 __ 30 Temperatureand Valve Pressure 30 Valve Materials ________.__.._._______I___________ 31 Non-Corrosive Service ___ 31 Corrosive Service 31 Chloride Stress Cracking Service 31 SuIfide Stress Cracking Service 31 References 31 - SECTION 4 FITTINGS AND FLANGES __ 32 General . . 32 Welded Flttmgs __ 32 . . Screwed Flttlngs 32 Branch Connections ___.__._._________________I_____ 32 Flanges 32 General __ 32 Gaskets 33 Flange 34 and Bolts Nuts ___ 34 Proprietary Connectors 34 Special Requirements for Sulfide Stress Cracking Service_""- -. 34 Erosion Prevention 34 References 34G SECTION 5 - PARTICULAR DESIGN CONSIDERATIONS FOR General 35 . . Wellhead Accessory Items 35 InJectlon andSampling Connections 35 Chokes 35 Flowline and Flowline Accessories 35 Flowline Pressure . Sensor . 35 Flowline Orifice Fitting 35 Flowline Heat 35 Flowline Check Valve __ 35 Flowline 35COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 5. A P I R P * 1 4 E 91 W 0732290 0 0 9 9 4 8 6 2 4 Institute Petroleum American TABLE OF CONTENTS (Continued) Page SECTION 5 (continued) Production Manifolds 35 General 35 Manifold Branch Connections 35 Manifold Valve Installation 35 .. Process Vessel Piping 35 Utility 38 Systems Systems Pneumatic 38 Air 38 Gas Systems 38 Water Fire 38ems Water Potable 38 Sewage 38 and Heating Fluid Glycol 38 Pressure Relief and Disposal Systems 40 General .. 40 Relief Device Plplng Plplng System Relief (Disposal) .. 40 40 Drain 40 Systemsns Pressure 41 Between Piping Bridge . . Gravity 41 Platforms 41 Risers 41 41 Sampling Valves _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ References 41 SECTION 6 - CONSIDERATIONS OF RELATED ITEMS 42 General 42 Layout 42 Elevations a . 42 Plplng Supports42 Other Corrosion Considerations 42 42 Protective Coatings for External Surfaces.--.---_---------------------- Types. of Platform Systems Piping Coating 42 Selection of Platform Piping Coating Systems 42 ___._______I___ Risers 42 Corrosion Protec.tion for Internal Surfaces 42 Process . . 42 Water 42 42 Protective Coatings ________________________________________-------------------------- . .. Compatlblllty of Materials 42 Non-Destructive Erosion and/or Corrosion Surveys 43Protection Cathodic 43 Thermal 43 Noise a . 43 Pipe, Valves and FittingsTables: _____________._.______ 43 Inspection, Maintenance & Repalr ______.__________...__ 43 COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 6. A P I R P * 1 4 E 91 m 0732290 0099487 4 m RP 14E: Offshore ProductionPiping Platform Systems 6 Attention Users of this Publication: Portions of this publication havebeen changed from the previous edi- tion. The locqtions of changes have been marked with a bar in the margin, as shown to the left of this para- graph. In some cases the changes are significant, while in othercases the changes reflect minoreditorial adjustments. The bar notations in the margins are pro- vided as an aid to users as to those parts of this publica- tion that have been changed from the previous edition, but API makes no warranty as to the accuracy of such bar notations. NOTE: This is the fifth edition of this Recommended Requests for pemnissimt to reproduce or translate all or Practice. It inclztdes changes tothe fotwth edition adopted ayzy part of thewtaterial pblished herein should be at the 1990 Standardization Co?zferenee. addressed to the Directar, Awlerican Petroleum Institute Production Department, 2535 One Main Place, Dallas This statzdard shall become effective on the date printed TX 75202-3904. m~the cover, but mau be used volzmtarilu from the date of distribution.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 7. A P I RPULqE 71 0732290 0077488 b m 6 Institute Petroleum American POLICY STATEMENT API PUBLICATIONS NECESSARILY ADDRESS ANEXTENSION BEEN HAS GRANTED,UPON PROBLEMS OF A GENERAL NATURE. WITH REPUBLICATION.STATUS OF THIS PUBLICA- RESPECT TO PARTICULAR CIRCUMSTANCES, TION CAN B E ASCERTAINED FROM THEAPI LOCAL,STATE,ANDFEDERALLAWSAND AUTHORING DEPARTMENT (TEL. 214-748-3841). A REGULATIONS SHOULDBE REVIEWED. CATALOG O F APIPUBLICATIONS AND MATE- RIALS IS PUBLISHED ANNUALLY AND UP- API IS NOT UNDERTAKING TO MEETDUTIES DATED QUARTERLYBYAPI, 1220 L ST., N.W., OF EMPLOYERS,MANUFACTURERS, OR SUP- WASHINGTON, D.C. 20005. PLIERS TO WARN AND PROPERLY TRAIN AND EQUIPTHEIREMPLOYEES, AND OTHERSEX- American Petroleum Institute (API) Recommended POSED,CONCERNING HEALTH AND SAFETY Practices are publishedto facilitatethe board avail- RISKS AND PRECAUTIONS, NOR UNDERTAKING ability of proven, sound engineering and operating prac- THEIR OBLIGATIONS UNDER LOCAL, STATE, OR tices. These Recommended Practices are not intended to FEDERAL LAWS. obviate the need for applying sound judgment as to NOTHING CONTAINED IN ANY API PUBLICA- when and where these Recommended Practices should TION IS TO BE CONSTRUED AS GRANTING ANY be utilized. RIGHT, BY IMPLICATION OR OTHERWISE,FOR THEMANUFACTURE,SALE, OR USE OF ANY The formulation and publication of API Recommended METHOD, APPARATUS, OR PRODUCT COVERED Practices is not intended to, in any way, inhibit anyone BY LETTERS PATENT. NEITHER SHOULD ANY- from using any other practices. THING CONTAINED IN THIS PUBLICATION BE CONSTRUED ASINSURING ANYONEAGAINST Any Recommended Practicemaybe used by anyone LIABILITYFORINFRINGEMENT OFLETTERS desiring to do so, and a diligent effort hasbeen made by PATENT. API to assure the accuracy and reliability of the data containedherein. However, the Institute makes no GENERALLY, API STANDARDS ARE REVIEWED representation, warranty or guarantee in connection AND REVISED, REAFFIRMED, OR WITHDRAWN with the publication of any Recommended Practice and AT LEAST EVERY FIVE YEARS. SOMETIMES A hereby expressly disclaims any liability or responsibil- ONE-TIME EXTENSION OF UP TO TWO YEARS ity for loss or damage resulting from its use, for any WILL BE ADDED TO THIS REVIEW CYCLE. THIS violation of any federal, state or municipal regulation PUBLICATION WILL NO LONGER BE IN EFFECT with which an API recommendation may conflict, or for FIVEYEARSAFTERITSPUBLICATIONDATE the infringement of any patent resulting from the of use AS AN OPERATIVE API STANDARD OR, WHERE this publication.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 8. A P I RP*kL4E 91 m 0732290 0099489 B m RP 14E:Offshore Systems Piping Production Platform 7 FOREWORD a. This recommended practice (RP) is under the juris- IMPACT ENERGY diction of the American Petroleum Institute (API) 1 foot-pound = 1.355818 Joules (J) Committee on Standardization of Offshore Safety (ft-lb) andAnti-PollutionEquipment. It has been pre- paredwiththeoveralladvisoryguidance of the API, Offshore OperatorsCommittee(OOC),and theWestern Oil andGasAssociation(WOGA). TORQUE Corrosion related sections were prepared with the 1 foot-pound ~1.355818 newton- assistance of the National Association of Corro- (ft-lb) metres (Nam) sion Engineers (NACE), b. This RP contains information for use primarily by a design engineers with working knowledgeof pro- TEMPERATURE duction platform operations. Some of the informa- tion may be useful to experienced operating per- The following formula mas used to convert degrees sonnel. Nothing in this RP is to be construed as a Fahrenheit (F) degrees Celsius (C): to fixed rule withoutregardtosoundengineering C = 5/9 (F-32) judgement nor is it intended to supercede or over- ride any federal, state, or local regulation where applicable. VOLUME c. Conversion of English units to International System 1Cubic Foot (CUft) = 0.02831685 Metre Cubic (m3) (SI) metric units has been omitted to add clarity to 1Gallon (gal) =0.003785412 Cubic graphs and empirical formulas. Factorsthat may be Metre (m3) used for conversion of English units to SI units were 1 Barrel (bbl) =0.1589873 Cubic takenfrom API Publication 2564, andarelisted below: Metre (m3) LENGTH WEIGHT 1 inch (in.) ~25.4millimetres (mm) 1 pound (lb) ~0.4535924 Kilograms (kg) exactly PRESSURE FORCE 1 pound per =0.06894757 Bar 1 pound (lb) = 4.448222 Newtons (N) square inch (psi) NOTE: 1 Bar = 100 kilopascals (kPa) FLOW RATE 1 Barrelperday(BPD) =0.1689873 Cubic Metres STRENGTH OR STRESS per day(m3/d) 1pound per = 0.006894757 Mega- 1 Cubic foot per min (CFM) =40.77626 Cubic Metres square inch (psi) pascals (MPa) per day(m3/d) DEFINITIONS Thefollowing definitions apply specifically to the CORROSIVE -Process streams which con- equipment and systems described in this RP. HYDROCARBON tain water or brine and car- CHLORIDE STRESS -Process streams which con- SERVICE bon dioxide ( C O Z ) , hydro- CRACKING SERVICE tain water and chlorides un- gen sulfide (HzS), oxygen der conditions of concentra- (OZ)orothercorrosive tion and temperature high agentsunderconditions enoughtoinduce stress which causemetalweight cracking of ferrous base al- loss. loy materials. Other con- DESIGN PRESSURE -Maximumallowablework- stituents present,such as ing pressure at the design oxygen(02),maycontrib- temperature. ute to such chloride stress EXPANSION -A corrugated piping device cracking. BELLOWS designed for absorbing ex- pansion and contraction. CHOKE -A device specifically in- EXPANSION BEND -A pipingconfiguration de- tended to restrict the flow signed to absorb expansion rate of fluids. and contraction. CORROSION- -The phenomenon of a-pro- FIRE WATCH “Oneor moretrainedper- EaOSION tective film of corrosion sons withoperable fire product being eroded away fighting equipment stand- by the erosive action of the ing on alert during welding processstream, exposing or burning operations. fresh metal which then cor- FLOWLINE -Piping which carries well rodes. Extremely high met- fluid wellhead from to al weightlossmay occur manifold or process first under these conditions. vessel. CORROSIVE GAS -A gas which when dissolved FLOW REGIME -The flow condition of a mul- in water or other liquid tiphase process stream such causes metal attack. Usual- as slug, mist,orstratified ly included are hydrogen flow. sulfide (HzS), carbon di- FLUID -A generic term meaning a oxide (COZ) oxygen and gas, vapor, liquid or com- (02).COPYRIGHT American Petroleum Institute binations thereof.Licensed by Information Handling Services
  • 9. A P I R P * 1 4 E 91 M 0732290 0099490 4 m 8 Institute Petroleum American HEADER -That part of a manifold PRESSURE SENSOR -A device designed to detect which directs fluid to a a predetermined pressure. specific process system. PROCESS -A single functional piece of (See Figure 6.1A) COMPONENT production equipment and HYDROCARBON -The ability of the process associated piping such as a WETABILITY stream form to a protective pressure vessel, heater, hydrocarbon filmon metal pump, etc. surfaces. RISER -The vertical portion of a MANIFOLD -An assembly of pipe, valves, pipeline (including the bot- and fittings by which fluid tombend)arriving on or fromone or moresources departing from a platform. is selectivelydirected to various process systems. SHUTDOWN VALVE -An automatically operated NIPPLE -A section of threaded or valve for used isolating a socket welded pipe used as process J component or proc- an appurtenance that is less ess system. than 12 inches in length. SULFIDESTRESS "Process streams which con- NON-CORROSIVE -Process streams under con- CRACKING SERVICE tain water or brine andh?- HYDROCARBON ditions which do not cause drogensulfide (H2S) in SERVICE significant metal weight concentrations high enough loss, selective attack, or to induce stress corrosion stress corrosion cracking. cracking of susceptible PLATFORM PIPING -A general term referring to materials. any piping,on a platform, WELLHEAD -The maximum shut-in sur- intended to contain or trans- PRESSURE face pressure that may exist port fluid. in a well. SYMBOLS The following symbols apply specifically to the equa- = pressure drop,.- _ psi/lOO f t tions contained in thisRP. = gas flow rate, million cubic feet/day (14.7 A = minimumpipecross-sectional flow area psia and 60°F) required, inches2/1000 barrels fluid/day = liquid flow rate, barrels/day B mean coefficient of thermal expansion at = gas flow rate, cubic feet/hour (14.7 psia operating temperatures normallyencoun- and 60°F) tered, inches/inch/"F = gas/liquid ratio, standard cubic feet/bar- C = empirical pump constant re1 C = empirical constant = Reynolds number, dimensionless cv = valve coefficient (GPM water flow at 60°F = pump speed, revolutions/minute acrossvalvewith a pressuredrop of 1 = gas density a t operating pressure and Psi) temperature, lbs/fts dr = pipe inside diameter, feet = liquid density.at operating temperature, di = pipe inside diameter, inches lbs/ft3 D = nominal pipe diameter, inches = gasfliquid mixture density at operating D O = pipe outside diameter, inches pressure and temperature, lbs/ft3 E = longitudinal weld joint factor, dimension- = allowable stress, psi less = gas specific gravity (air = 1) Em = modulus zf elasticity o$ piping material = liquid specific gravity (water = 1) in the cold condition, psi = operating temperature, O R (See Note (2)) f = Moody friction factor, dimensionless = pressure design thickness, inches g = gravitational constant, feet/secondz = temperature change, "F GPM = liquid flow rate, gallons/minute ha = acceleration head, feet of liquid = anchordistance,feet(straightlinedis- tance between anchors) hr = friction head, feet of liquid = gas viscosity a t flowing pressure and hp = absolute pressure head, feet of liquid temperature, centipoise hst = static head, feet of liquid = liquid viscosity, lbs/ft-sec hvh = velocity head, feet of liquid = fluid erosional velocity, feet/second hvpa = absolute vapor pressure, feetof liquid = average gasvelocity, feetlsecond (See Note (3)) Ahw = differential static pressure head, inchesof = average liquid velocity, feet/second water K = acceleration factor, dimensionless = total liquid plus vapor rate, lbs/hr L = pipe length, feet = temperature factor, dimensionless Al = expansion to be absorbed by pipe, inches = gas compressibility factor, dimensionless NPSHa = available net positive suction head; feet of liquid NOTES: P = operating pressure, (See psia Note (1)) (1) Also denoted in test as ;flmuiTzg pressure, psia.." Pi = internal pressure, design psig (2) Also denoted in t e b as flowingkmperature, OR;," Ap = pressure psi drop, () Also denoted in t e d as "gas vebctty, feetlsecond. SCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 10. API R P * 3 4 E 9 3 W 0732290 O099493 b W RP 14E:Offshore Systems Piping Production Platform 9 SECTION 1 GENERAL 1.1 Scope. document This recommends minimum tings Industry) standards. Pressureltempera- requirements and guidelines for the design and installa- ture ratings and material compatibilityshould tion of newpipingsystems on productionplatforms be verified. located offshore. The maximum design pressure within e. In determining the transition between risers and the scope of this document is 10,000 psig andthe platformpipingtowhichthesepracticesapply, temperature range is -20’F to 650°F. For applications the first incoming and last outgoing valve which outside these pressures and temperatures, special con- blocks pipeline flow shall be the limit of this doc- sideration should be given to material properties (duc- ument‘s application.RecommendedPractices in- tility, carbon migration, etc.). The recommended prac- cluded in this document may be utilized for riser ticespresented are based on years of experience in design when factors suchas water depth, batter of developing oil and gas leases. Practically all of the off- pIatform legs, potentialbubbling area, etc., are shore experience has been in hydrocarbon service free considered. of hydrogen sulfide. However, recommendations based on extensive experience onshore are included for some 1.3 Policy. American Petroleum Institute (API) aspects of hydrocarbon servicecontaining hydrogen Recommended Practices are published to facilitate the sulfide. broadavailability of proven, sound, engineeringand operating practices. These Recommended Practices are a. This document contains both general and specific not intended to obviate the need forapplying sound information on surface facility piping systems not judgment as to when and where these Recommended specified in API Specification 6A. Sections 2, 3 Practices should be utilized. and 4 contain general information concerning the design and application of pipe, valves, and fittingsThe formulation and publication of API Recommended for typical processes. Sections 6 and 7 contain gen-Practices is not intended to, in any way, inhibit anyone eral information concerning installation, from using any other quality practices. control, and items related to piping systems, e.g., Nothing contained in any API Recommended Practice is insulation, etc. for typical processes. Section 5 con- to beconstrued as granting any right, implication or by tains specific information concerning the design of otherwise, for the manufacture, sale or use in connec- particular piping systems including any deviations tion with any method, apparatus, or product covered by from the recommendations covered in the general letters patent, nor as insuring anyone against liability sections. for infringementof letters patent. b. Carbon materials suitable the steel are for This Recommended Practice may be used byanyone majority of thepipingsystemsonproduction desiring to do so, and a diligent effort has been made platforms. At least one carbon steel material by API to assure the accuracy and reliability of the recommendation is included formost applica- data contained herein.However, the rnstitute makesno tions, Other materials that may be suitable for representation,warranty or guaranteein connection platform piping systems have notbeen included with the publication of this Recommended Practice and becausethey are not generally used. The fol- hereby expressly disclaims any liability or responsibil- lowing shouldconsidered selecting be when ity for loss or damage resulting from its use, for any materials other than those detailed in this RP. violation of any federal, state or municipal regulation (1) Type of service. withwhich an API recommendationmay conflict, or (2) Compatibility with other materials. for the infringement of any patent resulting from the (3) Ductility. use of this publication. (4) Need for special welding procedures. 1.4 Industry Codes, Guides and Standards. Various (5) Need for special inspection, tests, or quality organizations have developed numerous codes, guides control. and standards which have substantial acceptance by (6) Possible misapplication in the field. industry and governmental bodies. Listed below are (7) Corrosion/erosion caused by internal fluids the codes, guides and standards referenced herein. and/or marine environments. 1.2 Code forPressurePiping.The Included-by-reference standards shallbe the latest pub- lished edition unless otherwise stated. design and installation of platform piping should conform to ANSI I a. American Iron and Steel Institute. B31.3, as modified herein. Risers for which B31.3 is not AIS1 Products Steel Manual, Stainless and applicable, should be designed and installed is accord- Heat Resisting Steels. ance with the following practices: b. American National Standards Institute (For- a. Design, construction, inspection and testing should merly “ASA” and “USAS”). be in accordance with ANSI B31.4, ANSI B31.8, (1)-ANSI B2.1, Pipe Threads. CFR Title 49, Part 192, and/or CFR Title49, Part (2) ANSI B16.5, Steel Pipe Flanges, Flanged 195, as approprlatetothe appllcatlon, usmg a Valves, and Fittings. design stress no greaterthan 0.6 timesSMYS (Specified Minimum Yield Strength). (3) ANSI B16.9, FactoTV-Made Wrought Steel Buttwelding Fittings. b. One hundred percent radiography shouldbe requiredfor welding in accordancewithAPI (4) ANSI B16.10, Face-to-Face and End-to- Std 1104. End Dimensions of Ferrous Valves. c. Impact tests shouldberequired at the lowest (5) ANSI B16.11, Forged Steel Fittings, Sock- expected operating temperatures for pipe grades et-Welding and Threaded. higher than X-52. (6) ANSI B16.28, Wrought Steel Buttwelding Short Radius Elbows and Returns. d. Valves,fittingsandflangesmaybemanufac- tured in conformance with MSS (Manufacturers (7) ANSI B31.3, P e t r o l a m Refinery Piping.I Standardization Society of the Valve and Fit- (8) ANSI B31.4, Oil Transportation Piping. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 11. A P I R P x L 4 E 7% m 0732270 O077472 B W 10 Petroleum American Institute (9)ANSI B31.8, GasTransmissionandDis- (6) ASTM A194, Specification for Carbon and t?*ibution Piping Systems. A l l o y S t e e l N u t s f o r B o l t s o r High-Pres- f (10) ANSI B36.10, Wrought-Steel and Wrought sure and Hagh-Temperature Seruace. Iron Pipe. (7) ASTM A234, Specification f o r Piping Fit- tangs of Wrought Carbon Steel and Alloy c. AmericanPetroleumInstitute. Steel Moderate Elevated for and Tem- peratures. , (1) APIRP 2G, RecommendedPracticefor (8) ASTM A333, Specification f o r Seamless ProductionFacilitiesonOfishoreStruc- and Welded Steel Pipe for Low-Tempera- tures. ture Service. (2) API Bu1 5A2, BulletinonThread Com pounds Casing, for Tubing, Line and (9) ASTM A364, Specification f o r Quenched Pipe. andTemperedAlloySteelBolts, Studs, and Other Eoternally Threaded Fasteners. (3) API Spec SB, Specification for Threading, e. AmericanSociety of Mechanical Engineers. Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads. (1) ASMEBoilerandPressureVessel Code, (4) API Spec SL, Specification for Line Pipe. Section IV, Heating. (2) ASMEBoilerandPressureVessel Code, (5) A P I Spec 6A, Specification for Wellhead Section VIII, Pressure Vessels, Division 1. Equipment. (3) ASMEBoilerandPressureVessel Code, (6) APISpec 6D, SpecificationforPipeline Section IX, Qualification Standard for Valves. Welding and Brazing Proceduves, Welders, (7) API RP 14C, RecommendedPracticefor Brazers, and Welding and Brazing Oper- Analysis, Design, Installation and Testing ators. of Basic Surface Safetg Systems for Off- f. National Association of Corrosion Engineas shore Production Platforms. (8) API RP 510, Pressure Vessel Impection Code. (1) NACE Std MR-01-76, Sulfide Stress CrackiTzg Resistant MetallicMaterials for Oil Field (9) API RP 520, RecommendedPracticefor Equipwmt. DesignandInstallation of Pressure-Re- lieving Systems in Refineries, Parts I and (2) NACE Std. RP-01-76, Corrosion Control pn II. Steel, F i a d Offshore Platfot+msAssociated w a t h (10) A P I R P 521, Guide for PressureRelief Petroleum Production. and Depressuring Systems. g. National Fire Protection Association. (11) API Std 526, Flanged Steel Safety Relief (1) NationalFire Code Volume 6, Sprinklers, Valves. Fire Pumps and Water Tanks. (12) API RP550, Manual on Installation of Re- (2) National Fire Code Volume 8, Portable and finery Instruments and Control Systems, Manual Fire Control Equipment. Parts I and II. h. Gas Processors Suppliers Association (formerly (13) API Std 600, Steel Gate Valves (Flanged Natural Gas Processors Suppliers Association). or Buttwelding Ends). Engineering DataBooks. (14) APIStd 602, CarbonSteelGateValves i. HydraulicsInstitute. for Refinery Use (Compact Desagn) . (15) API Std 1104, Standard for Welding Pipe- (1) Standards for Centrifugal, Rotary and Re- lines and Related Facilities. ciprocating Pumps. (2) Pipe Friction Manual. (16) API Medical ResearchReport E A 7301, Guidelines on Noise. 15 Governmental . Rules Regulations. and Regu- latoryagencieshaveestablishedcertainrulesand d. American Society for Testing and Materials. regulations which may influence the nature and man- ner in which platform pipingis installed and operated. (1) ASTM A53, Specification for Welded and Listed below are references to significant rules and Seamless Steel Pipe. regulations which should be considered in the design (2) ASTM A105, Specification f o r Forgings, and installation of platform piping, where applicable. Carbon Steel, for Piping Components. a. Code of Federal Regulations. (3) ASTM A106, SpecificationforSeamless Carbon Steel Pipe for High-Temperature (1) Title. 29, Part 1910, Occupational Safety Semce. and Health Standards. (4) ASTM A153, Specification for Zinc Coat- (2) Title 30, Part 250, Oil and Gas and Sul- ing(Hot-Dip)onIronandSteelHard- phur Operations in the Outer Continental ware. Shelf, ( 6 ) ASTM A193, Specification f o r A l l o y s t e e l (3) Title 33, Subchapter C, A i d s to Naviga- and Stainless Steel Bolting Materìals for taon, Part 67, Aads to Navzgatzon on Ar- High-Temperature Service. tificial Islands and Fized Structures,COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 12. A P I RP*L4E 91 0732290 0099493 T RP 14E:Production Offshore Platform Piping Systems 11 (4) Title 33, Subchapter N, Artificial Zslands After the pressure is reduced, process components of andFixed Structures on the Outer Con- lower pressure rating may be used. A typical exam- , tinental Shelf Parts 140 through 146. ple is shown in Figure 1.1 (6) Title 33, Part 163, Control of Pollution by Oil and Hazardous Substances, Discharge a. One rulecan be used forpressuredesign: a Removal. pressurecontainingprocesscomponentshould (6) Title 40, P a r t 110, Discharge of Oil. either be designed to withstand the maximum internalpressure which can be exertedonit (7) Tjtle 40, Part 112, Oil PollutionPreven- under any conditions, or be protected by a pres- taon. surerelieving device. In this case, a pressure ( 8 ) Title 49, Part 192, Transportation of.Nat- relieving device means a safety relief valve or ural and Other Gas by Pipeline:Minzmum a rupture disc. In general, when determining if Federal Safety Standards. pressure relieving devices are needed, high pres- (9) Title 49, Part 196, Transportation of Liq- sure shutdown valves, checkvalves, control uids by Pipeline. valves or other such devices should not be con- sidered as preventingoverpressure of process b. Environmental Protection Agency. components. See API R P 14C for recommended Document AP-26, Workbook o f Atmospheric practices concerning required safety devices for Dispersion Estimates. process components. c. Regional Outer Continental Shelf Orders Promul- gatedUnderthe Code of Federal Regulations, b. One good way to analyze required system design Title 30, Part 260,0ilandGasSzclp.phu~Ope-rations pressureratingsforprocesscomponentsisto i n the Outer Contìnental Shelf. show pressure rating boundaries on mechanical d. State, municipal and other local regulatory agen- flow sheets.Eachcomponent(vessels,flanges, cies, as applicable. pipe o r accessories)maythenbe checked to determine thatitiseither designed towith- 16 DemarcationBetweenSystemswithDifferent . stand the highest pressure to which it could bePressure Ratings. Normally the after wellstream subjected, or is protected a pressure relieving byleaves the wellhead, the pressure is reduced in stages, device,COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 13. A P I R P * L 4 E 9L M 0732290 0 0 9 9 4 9 4 L 12 Institute Petroleum American ””” I- -COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 14. A P I R P * 1 4 E 91 W 0732290 O099495 3 W RP 14E: Offshore Production Platform Piping Systems 13 17 CorrosionConsiderations. . TABLE 1.1 QUALITATIVE GUIDELINE FOR WEIGHT a. General. Detailed corrosion control practices for platform piping systems are outside the scope LOSSCORROSION OF STEEL of thisrecommendedpractice.Suchpractices should,ingeneral,bedevelopedbycorrosion Limiting Valoes in Brine control specialists. Platform piping systems should,however, be designed to accommodate and to be compatible with the corrosion control 9010- bility* n corrosive Corrosive Corrosive gas P m wn1 PPM practices described below. Suggestions for cor- rosion resistant materials and mitigation prac- Oxygen ( 0 2 ) 8 <0.005 >0.025 ticesaregivenintheappropriatesections of >1200 this RP. Carbon Dioxide (COZ) 1700 <SOO ** Hydrogen Sulfide (H2S) 3900 ** NOTE : The corrosivitu of process streams may *Solubility a t W F in distilled water a t 1 atmosphere partial change with time. The possibilitiy of changing pressure. Oxygen (02) is for 1 atmosphere air pressure. conditions should beconsidered at thedesign Source: Handbook of Chemistry and Physics, Chemical Rub- berCompany,36th Edition. stage. **No limiting values for weight loss corrosion by hydrogen sulfide (HzS) are shown inthis table because the amount of carbon b. WeightLossCorrosion.Carbonsteelwhich is dioxide (COZ) and/or oxygen ( 0 2 ) greatly influences the metal generally utilized for platform piping systems loss corrosion rate. Hydrogen sulfide alone is usually less cor- rosive than carbon dioxide due to the formation of an insoluble may corrodeunder process some conditions. iron sulfide film which tends t reduce metal weight loss o Productionprocessstreamscontainingwater, corrosion. brinecarbondioxide(C02) , hydrogensulfide (HzS), oroxygen ( 0 2 ) ,or combinations of these, may be corrosive to metals used in system com- hydrogen sulfide concentration, stress and tem- ponents. The type of attack (uniform metal loss, perature. Materials used tocontain process pitting,corrosion/erosion,etc.) as well as the streams containing hydrogen sulfideshould be specificcorrosion rate may vary in the same selected to accommodate these parameters. system, and may vary with time. The cor- d. ChIoride Stress Cracking. Careful consideration rosivity of a process stream is a complex should be given to the effect of stress and chlorides function of many variables including (1) hydro- if alloy and stainless steels are selected to prevent carbon,water,salt,andcorrosive gas content, corrosion by hydrogen sulfide and/or carbon diox- (2) hydrocarbon vretability, (3) flow velocity, ide. Process streams whichcontainwaterwith flow regime, and piping configuration, (4) tem- chlorides may cause cracking in susceptible mate- perature,pressure, pH, and and (5) solids rials, especially if oxygen is present and the content (sand, mud, bacterial slime and micro- temperature is over 140°F. High alloy and stain- organisms, corrosion products, and scale). Cor- less steels, such as the AIS1 300 series austenitic rosivitypredictions areveryqualitativeand stainlesssteels,precipitationhardeningstainless may be unique foreachsystem.Somecorro- steels, and "A-286" (ASTM A453, GFade. 660), sivity information for corrosive gases found in should not be used unless their sultablllty ln the production streams is shown in Table 1.1. proposed environment has been adequately dem- onstrated.Considerationshould also be given to the possibility that chlorides may be concentrated Table 1.1is intended only as a general guide for in localized areas in the system. corrosion mitigation considerations and not for specific corrosivity predictions. Corrosion inhibi- e, Application of NACE MR-01-75. MR-01-75 lists tion is an effective mitigationprocedure when materials which exhibit resistance to sulfide stress corrosive conditions are predicted or anticipated cracking.Corrosion. resistant alloysnot listed in (See Paragraph 2.l.b). MR-01-75 may exhibit such resistance and may be used if it can be demonstrated that they are resist- c. Sulfide Stress Cracking. Process streams con- ant in the proposed environment of use (or in an taining water and hydrogen sulfide may cause equivalent laboratory environment). Caution should sulfide stress cracking of susceptible materials. be exercised in the use of materials listed in MR- This phenomenon is affected by a complex inter- 01-75. The materials listed in the document may be action of parameters including metal chemical resistant to sulfide stress corrosion environments, composition and hardness, heat treatment, and but may not be suitable for use in chloride stress microstructure, as well as factors such as pH, cracking environments.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 15. A P I R P * 1 4 E 91 W 0732290 0 0 9 9 4 9 b 5 W 14 Institute Petroleum American SECTION 2 PIPINGDESIGN 2.1 Pipe Grades. cations or systemswhich external in the a. Non-Corrosive Hydrocarbon Service. two The environmentandtheprocessstream canbe most commonly used types of pipe are ASTM continuously maint.ained to assurefreedom fromsulfidestress cracking, or limited to A106, Grade B, and API 5L, Grade B. Seamless those materials for which adequate data exists pipe is generally preferred due to its consistent to demonstrate resistance to sulfide or chloride quality. ASTM A106 is onlymanufacturedin stresscracking in theapplication or system seamless while API 5L is available in seamless, environments to which the materials are electric resistance weldcd (ERW) and sub- exposed, (SeeMR-01-75). merged arc welded (SAW). When use of Grade B requires excessive thickness, wall higher The most commonly used pipe grades which will strength pipe such as API 5L, Grade X52, may meetthe above guidelinesare: ASTM A106, be required; however, special weldlng procedures Grade B; ASTMA333, Grade 1; and API SL, and close supervision are necessary when using Grade B, seamless.API5L X grades are also API 5L, GradeX46,or higher. acceptable;however,weldingpresentsspecial Many of the grades of pipe listed in ANSI B31.3 problems. To enhance toughness and reduce brittle are suitable for non-corrosive hydrocarbon fracture tendencies,API 5L pipeshould be nor- service. The following types or grades of pipe malized for servicetemperatures below 30 F. ASTM A333, Grade1,is a cold servicepiping are specifically excluded from hydrocarbon ser- materialand shouldhaveadequate notch tough- vice by ANSIB31.3: ness in the temperature range covered by this RP (1) All grades of ASTM A120. (-20" to 650F). (2) Furnace lap weld and furnace buttweld. (3) Fusion weld per ASTM A134 and A139. d. UtilitiesService.Materialsotherthancarbon (4) Spiral weld, except API5L spiral weld. steel are commonly used in utilities service. If, however, steel pipe is used that is of a type or b. Corrosive Hydrocarbon Service. Design for cor- gradenotacceptableforhydrocarbon serviCe rosive hydrocarbon service should provide for one in accordance with Paragraph 2.l.a, some defi- or more of the following corrosion mitigating nitemarkingsystem should be establishedto practices: (1) chemical treatment; (2) corrosion re- prevent such pipe from accidentally being used sistant allo s; (3) protectivecoatings(See Para- in hydrocarbon service. One way to accomplish graph 6.5.bY. Of these, chemical treatment of the this would be t o have all such pipe galvanized. fluidincontactwithcarbon steels is by far the most common practiceandisgenerally recom- e. Tubing. AISI 316 or AISI 316L stainless steel, mended. Corrosion resistant alloyswhich have seamlessorelectricresistancewelded tubing is provensuccessfulin similarapplications (or by preferred for allhydrocarbonservice,and air suitablelaboratorytests)maybeused. If such serviceexposedtosunlight. Tubing usedfor air alloys are used,carefulconsiderationshould be service notexposed to sunlight, or instrument tub- given to welding procedures. Consideration should ing used for gas service contained in an enclosure, also be given to the possibility of sulfide and.chlo- may be made of other materials. If used, synthetic ridestresscracking (See Paragraphs 1.7.c and tubing should be selected to withstand degradation 1.7.d). Adequate provisionsshould made be for caused by the contained fluids and the tempera- corrosion monitoring (coupons, probes,spools, etc.) ture to which it may be subjected. and chemical treating. 2.2 Sizing Criteria-General. In determining the c. Sulfide StressCrackingService.Thefollowing diameter of pipe to be used in platform piping sys- guidelines should be used when selecting pipe if tems, both the flow velocity and pressure drop should sulfide stress corrosion cracking is anticipated: be considered. Sections 2.3, 2.4 and 2.5 present equa- (1) Only seamlesspipeshould beusedunless tions for calculating pipe diameters (and graphs for quality control applicable to this service has rapidapproximation of pipe diameters) liquid for beenexercisedinmanufacturingERW or lines, single-phase gas lines, and gas/liquid two-phase SAW pipe. lines, respectively. Many companies also use compu- ter programs to facilitate piping design. (2) Cold expanded should pipe not be used unlessfollowedbynormalizing,quenching a. When determining sizes, maximum line the andtempering,tempering,orheattreat- flow rate expected during the lifeof the facility ment as described in 2.l.c(4). should be considered rather than the initialflow (3) Carbon and alloy steels and other materials rate. It is usually also advisable t o add a whichmeettheproperty,hardness,heat surge factor of20 to 50 percent to the antici- treatment and other requirements NACE of patednormal flow rate,unlesssurgeexpecta- MR-01-75 are acceptable for use in sulfide tionshave been morepreciselydeterminedby stress cracking service. pulse pressure measurements in similar systems or by specific fluid hammer calculation. Table2.1 (4)Materials not meetingthemetallurgicalre- presents some typical surge factors that may quirements of NACE MR-01-75 may be used; be used if more definite informationnot is however,usageshould limited be to appli- available.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 16. A P I RPsLLIE 91 m 0732290 0099LI97 7 W RP 14EProduction Systems Piping Offshore Platform 16 In diameter large flow lines producing liquid- where: vapor phase fluids between platforms throughriser systems, surge factors have been known t exceed o A P = pressure drop, psi/lOO feet. 200% due to slug flow. Refer to liquid-vapor slug f = Moody friction factor, dimensionless. flow programs generally available to Industry for QI = liquid flow rate, barrelslday. evaluation of slug flow. SI = liquid specific gravity (water = 1). TABLE 2.1 di = pipe inside diameter, inches, TYPICAL SURGE FACTORS (3) The Moody friction factor, f, is a function of the Reynolds number and the surface rough- Service Factor ness of the pipe. The modified Moody diagram, Figure 2.3, may be used to determine the fric- Facility handling primary production tionfactoroncetheReynoldsnumberis from its own platform 20% known. The Reynoldsnumbermay be deter- mined by the following equation: Facility handling primary production from another platform or remote well in less than 150 feet of water 30% Eq. 2.3 Facility handling primary production from another platformor remote well in greater where: than 150 feet of water 40% Re = Reynolds number, dimensionless. Facility handling gas lifted production from pl = liquid density, lb/ft3. its own platform 40% Facility handling gas lifted production from df = pipe inside diameter, ft. another platform or remote well 50 9’0 VI = liquid flow velocity, ft/sec. pl = liquid viscosity, lb/ft-sec, or b. Determination of pressure drop in a line should = centipoise divided by 1488, or include the effect of vaIves and fittings. Manu- = (centistokestimes specific gravity) facturer’sdataoranequivalentlengthgiven divided by 1488. in Table 2.2 may be used, b. Pump Piping. Reciprocating, rotary and centrif- c. Calculatedlinesizesmayneedtobeadjusted ugalpumpsuctionpipingsystems shouldbe in accordance with good engineering judgment. designed so the availablenetpositivesuction head (NPSH) at the pump inlet flange exceeds the pump required NPSH. Additionally, provi-I 2.3 Sizing Criteria For Liquid Lines. sionsshould be made reciprocating in pump suctionpiping minimize to pulsations. Satis- a. General. Single-phase li uid lines should be sized factory pump operation requires that essentially primarily on the basis 01 flow velocity. For lines transporting liquids insingle-phase from one pres- no vapor be flashed from the liquid as it enters the pump casing or cylinder. sure vessel to another by pressure differential, the (1) In a centrifugal or rotary pump, the liquid flow velocity shouId not exceed 15 feet/second a t pressure at the suction flange must be high maximum flow rates, to minimize flashing ahead of the control valve. If practical, flow velocity enough to overcome the pressure drop be- should not be less than 3 feet/second to minimize tweentheflangeandtheentrancetothe deposition of sand and other solids. At these flow impeller vane (or rotor) and maintain the velocities, the overall pressure drop in the iping pressure on the liquid above its vapor pres- will usually be small. Most of the pressure &op in sure. Otherwise cavitation will occur. In a liquid between pressure lines two vessels will reciprocating unit, the pressure a t t h e SUC- occur in theliquid dump valve and/orchoke. tionflange mustmeetthesamerequire- ment; the but pumprequired NPSH is (1) Flow velocities in liquid lines may be read typicallyhigher for than centrifugal a from Figure 2.1 or may be calculated using pump because of pressure drop across the the following derived equation: valves and pressure drop caused by pulsa- tion the in flow. Similarly, the available NPSH supplied to the pump suction must Eq. 2.1 account for the acceleration in the suction where: piping caused by the pulsating flow, as well as the friction, velocity and static head. VI = average liquid flow velocity, feet/ (2) The necessary available pressure differen- second. tial over the pumped fluid vapor pressure Qr = liquid flow rate, barrels/day. may be defined as net positive suction head dt = pipe inside diameter, inches. available(NPSHa). It is the total headin feet absolute determined at he suction (2) Pressuredrop(psiper 100 feet of flow nozzle, less vapor the pressure of the length) for single phase liquid lines may be liquid infeet absolute. AvailableNPSH read from Figure 2.2 or may be calculated should always equal or exceed the pump’s using the following (Fanning) equation : required-NPSH. Available NPSH for most A P = 0.0011Sf Q I ~ S I E .2.2 q pump applications may be calculated using di5 Equation 2.4. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 17. A P I RP*(/4E 91 m 0732290 0037478 7 m 16 Institute Petroleum American C .- O c V O L c c O C o o V V a v) c C Q E o 01 - L O c W m m w m o O M O m 0 0 O 0 0 O m o - "- N N N n n n ln00 O 0 0 O 0 0 O 0 0 O W 0 amo m o n m m m N N O N * O W N N N N nneCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 18. ~~ A P I R P r L 4 E 91 I 0732290 0099499 O I RP 14E: Offshore Production Platform Piping Systems 17 LIQUID FLOW VELOCITY, FEET/SECONDCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 19. A P I RP*lt4E 91 m 0732290 0099500 3 H 18 American Petroleum Institute PRESSURE DROP PSI/lOO FEETCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 20. A P I R P 8 1 4 E 91 m 0732290 0099503 5 m RP 14E:Offshore Production Platform Piping Systems 19COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 21. API RP*LYE 91 m 0732290 0099502 7 m 20 Petroleum American Institute NPSHa = hp - hvpa + hst - hf - hvh - ha = 2.0 for most hydrocarbons; Eq. 2.4 = 2.5 forrelativelycompressibleliq- where: uid (hot oil or ethane), g = gravitational constant (usually 32.2 h,, absolutepressureheadduetopres- feet/secondZ). sure, átmospheric or otherwise, on surface of liquidgoing to suction, It should be noted thatthereisnot uni- feet of liquid. versal acceptance of Equation 2.5 or of the hvpa = the absolute vapor pressure of the effect of acceleration head (See References liquid a t suction temperature, feet b, c and d, Section 2.10). However, Equation of liquid. 2.5 is believed to be a conservativebasis which will assure adequate provision for hst = static head, positive or negative, acceleration head. due t o liquidlevelabove or beIow datum (centerline line of pump), (4) When more than one reciprocating pump is feet of liquid. operated simultaneously on a common feed hf = frictionhead, or head loss due to line, at times all crankshafts are in phase flowing friction in the suction pip- and, to the feed system, the multiple pumps mg,includingentrance exit and act as one pump of that with type a losses, feet of liqdid. capacityequal t o that of allpumps com- bined, Inthis case, themaximuminstan- V12 taneous velocity in the feed line wouldbe hvh = velocity head= -,feet of liquid. equal to that created by one pump having 2g a capacity equal to that of all the pumps ha = accelerationhead,feet of liquid. combined. V = velocity of liquid inpiping,feet/ 1 ( 6 ) If the acceleration head is determined to be second. excessive, the following should eval- be g = gravitational constant (usually32.2 uated: feet/second2). (a) Shorten suction line. Acceleration head (3) For a centrifugal or rotary pump, the accel- is directly proportional t o line length, eration head, ha, is zero. For reciprocating L. pumps, the acceleration head is critical and (b) Use larger suction pipet o reduce veloc- may be determined by the following equa- ity. This is very helpful since velocity tion from the Hydraulics Institute: varies inversely with the square pipe of inside-diameter. Acceleration head is Eq. 2.5 directlyproportionalto fluid velocity, VI. where: (c) Reduce required pump speed by using ha = acceleration head, feet of liquid. a larger size piston or plunger, if per- mitted by pump rating. Speed required L = length of suction line, feet (actual is inversely proportional to the square length, not equivalent length). of pistondiameter.Accelerationhead VI = average liquidvelocity suction in is directly proportional t o pump speed, line, feet/second. RP. Rp = pump speed, revolutions/minute. (a) Consider a pump with a larger number C = empiricalconstantforthetype of of plungers, For example: C = .O40 pump : for a quintuplex pump. Thisisabout 40% less than C = .O66 for a triplex = ,200 for simplex double acting; pump. Acceleration is head directly ,200 for duplex single acting; proportional toC. = .115 for duplex double acting; (e) Consider using a pulsationdampener = ,066 for triplex singleor double act- if the above remedies are unacceptable. ing; The results obtainable using a damp- by = ,046 fbr quintuplex single or double ener in the suction system dependon acting; the size,type,location,andcharging pressure used. A good, properly located = .O28 for septuplex single or double dampener, if kept properly charged, acting. may reduce L, the length of pipe used NOTE: The constant C will vary in acceleration equation, head to a from these valuesfor unusual ratios value of 5 to 15 nominal pipe diameters. of connecting length crank rod to Dampeners should belocated as close radius. to the pump suction as possible. K = a factor representing the reciprocal (f) Use a centrifugal booster pump to of thefraction of thetheoretical charge the suction of the reciprocating acceleration which head must be pump. provided to avoid a noticeable dis- (6) The following guidelines may be useful in turbance in the suction piping: designing suction piping: = 1.4 for liquid with almost no com- (a) Suction pipingshouldbeone or two pressibility (deaerated water) ; pipesizes larger than the pumpinlet = 1.6 for amine,glycol, water; connection.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 22. A P I RP*(/4E 91 m 0732290 0099503 9 m RP 14E:Piping Production Offshore Platform Systems 21 (b) Suctionlinesshouldbeshortwith a be a noise problem if it exceeds 60 feet/second; how- minimum number of elbows and fit- ever, the velocity of 60 feet/second should not be inter- tings. preted asanabsolutecriteria.Higher velocities are (c) Eccentric reducers should be used near acceptable when pipe routing, valve choice and place- the pump, with the flat side up to keep ment aredone to minimize or isolate noise. the top of the line level. This eliminates the possibility of gas pocketsbeing The design of any piping system where corrosion inhi- formed in the suction piping, If poten- bition is expected tobe utilizedshouldconsiderthe tial for accumulation of debris is a con- installation of additional wall thickness in piping design cern, means for removalisrecom- and/orreduction of velocity to reducetheeffect of mended. stripping inhibitor film from the pipe wall. In such sys- tems it is suggested that a wall thickness monitoring (d) For reciprocating pumps, provide a method be instituted. suitablepulsationdampener (or make provisions for adding a dampener a t a a. General Pressure Drop Equation. later date) as close to the pump cylin- der as possible. 2 S QiZTlfL P: - Pz =25.2 Eq. 2 6 . (e) In multi-pump installations, the size common feed line so the velocity will where: - r15 be as close as possible to the velocity in the laterals going to the individual P1 = upstream pressure, psia pumps. This will avoid velocity changes and thereby minimize acceleration head P2 = downstream pressure, psia effects. S = gas specific gravity at standard conditions (7) Reciprocating, centrifugal and rotary pump discharge pipingshould be on sized an Qg = gas flow rate, MMscfd (at 14.7 psig and economical basis,Additionally,reciprocat- 60°F) ing pump discharge piping should be sized to minimize pulsations.Pulsations re- in Z = compressibility for(Refer factor gas to ciprocating discharge are pump piping GPSA Engineering DataBook) alsorelatedtotheaccelerationhead,but are more complex than suction piping pul- T1 = flowing temperature, "R sations.Thefollowingguidelinesmay be useful in designing discharge piping: f = Moody friction factor, dimensionless (refer ( a ) Discharge piping should be as short to Figure 2.3) and direct as possible. d = pipe ID, in. (b) Discharge piping should be one or two pipe sizes larger than pump discharge L = length, feet connection. Rearranging Equation2.6 and solvingfor Qg we have: (c) Velocity in discharge piping should not exceed three times the velocity in the suction piping. This velocity will nor- Eq. 2.7 mally result in an economical line size for all pumps, and will minimizepul- sations in reciprocating pumps, An approximation of Equation 2.6 can be made when the change in pressure is less than 10%of the inlet pres- (d) For reciprocating pumps, include a sure. If this is true, can make the we assumption: suitable pulsation dampener (or make provisions for adding a dampener a t a Eq. 2.8 later date) as close to the pump cylin- der as possible. Substituting in Equation 2.6 we have: (8) Table 2.3 may beused todeterminepre- liminary suction and discharge line sizes. AP = 12.6 S Q ZTlfL - Eq. 2.9 PId5 TABLE 2 3 . b. Empirical Pressure Drop. Several empirical TYPICAL FLOW VELOCITIES equations have been developed so as to avoid solv- ing for the Moody Friction Factor. All equations Suction Discharge are patterned after the general flow equation with Velocity Velocity various assumptions relativeto the Reynolds Num- (feet per (feet per ber.Themost common empiricalpressuredrop second) second) equation for gas flow in production facility piping is the Weymouth Equation describedbelow: Reciprocating Pumps Speeds up to250 RPM 2 6 1. Weymouth Equation. _____.1% Speeds 251-330 RPM ..____ 4% Speeds above330 RPM .___ .___1 ~ 3 This equation is based on measurements of com- Pumps Centrifugal 2-3 6-9 pressed air flowing in pipes rangingfrom 0.8 inches to 11.8 inchesin the range of the Moody diagram where the [/d curves are horizontal (i.e., I 2.4 SizingCriteriaforSingle-phase Gas Lines. high Reynolds number). In this range the Moody Single- hase gas lines should be sized so that the result- friction factor is independent of the Reynolds ing e n j pressure is high enough to satisfy the require- numberanddependent upon therelativerough-1 ments of the next piece of equipment. Also velocitymay ness. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 23. A P I RPsL4E 91 m 0732290 0099504 O m 22 Petroleum American Institute The Weymouth equation canbe expressed as: In practice, the Panhandle equation is commonly used for large diameter (greater than 10") long pipelines (usually measured in miles rather than feet) where the Reynolds number is on the straight line portion of the Moody diagram, It can be seen where: thatneitherthe Weymouth nor t h e Panhandle represent a "conservative" assumptlon. If the Wey- Q, = flow rate, MMscfd (at 14.7 psia and mouth formula is assumed, and the flow is a mod- 60°F) erate Reynolds number, the friction factor will in realitybehigher than assumed(the sloped line d = pipe ID, in. portion is higher than thehorizontal portion of the Moody curve), and the actual pressure drop will be PI and Pz = pressure at points 1 and 2 respectively, higher than calculated. If the Panhandle formula psla 1s used and the flow is actually I n a high Reynolds number, the friction factor will in reality be L = length of pipe, ft higherthan assumed(theequationassumes the friction factor continues to decline with increased S = specific gravity of gas standard at Reynolds number beyond the horizontal portion of conditions the curve), and the actual pressure drop will be higher thancalculated. T1 = temperature of gas at inlet, "R 3. Spitzglass Equation. Z = compressibility factor of gas (Refer to GPSA Engineering Data Book) Thisequation is used for near-atmosphericpres- sure lines. It is derived by making the following assumDtions in Eauation 2.7: It is important to remember the assumptions used in deriving equation this and when they are appro riate. Short lengths of pipe w i t h high res sure &ops are likely to be in turbulent flow &igh a. f - = (i+ -3.6 d + 0.03,) I () . 6 , Reynolds Numbers) thus and the assumptions b. T = 520"R g20"R made by Weymouth are appropriate. Industry experience indicates that the Weymouth equation c. Pl = 15 psi is suitable for most piping within the production facility. However, the friction factor used by d. Z = 1.0 for ideal gas Weymouth is generally too low for large diameter or low velocity lines where the flow regimeis e. AP <10%of P1 more properly characterized by the sloped portion of the Moody diagram. With these assumptions, and expressing pressure drop in terms of inches of water, the Spitzglass 2. Panhandle Equation. equation can bewritten: This equation assumes that the friction factor can be represented by a straight line of constant nega- Q, = 0.09 [ SL (1+h$+O.O3d)] Es. 2.12 tive slope in the moderate Reynolds number region of the Moody diagram. where The Panhandle equation can be written: h, = pressure loss, inches of water S = gas specific gravityatstandard conditions Q, = gas flow rate, MMscfd (at 14.7 psig and 60°F) Pl = upstream pressure, psia L = length, feet Pz = downstream pressure, psia d = pipe I.D., inches S , = gas specific gravity c. Gas Velocity Equation. Gas velocities may be cal- Z = compressibility factor for gas (Refer to culated usingthe following derived equation: GPSA Engineering Data Book) Q, = gas flow rate, MMscfd (at 14.7 psia, 60°F) Eq. 2.13 Tl = flowing temperature, "R where: L,, = length, miles V, = gas velocity, feet/second. d = pipe I.D., inches dl = pipe inside diameter, inches. E = efficiency factor Qg = gas flow rate, million cubic feet/day (at 14.7 psia and 60°F). = 1.0 for brand new pipe T = operating temperature, "R = 0.95 for good operating conditions P = operating pressure, psia = 0.92 for average operating conditions Z = gas compressibility factor (Refer to GPSA = 0.85 for unfavorable operating conditions Engineering DataBook)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 24. - A P I R P r L 4 E 91 m 0732290 0099505 2 m RP 14E:Production Systems Piping Offshore Platform 23 d. Compressor Piping. Reciprocating and centrifu- where: gal compressor piping should be sized to minimize P = operating pressure, psia. pulsation, vibration and noise. The selection of allowable velocities requires an engineering study S = liquid 1 specific gravity(water = 1; for each specific application. use average gravity for hydrocarbon- water mixtures)at standard conditions. e. General Notes. R = gas/liquid ratio, ft3/barrel a t standard (1) When using gas flow equations for old pipe, conditions. build-up of scale, corrosion, liquids, paraffin, T = operating temperature, “R. etc., can have a large effect on gas flow Sg = gas specific gravity (air= 1)at standard efficiency. conditions. (2) Forotherempirical equations, refer to the B = gas compressibility factor, dimensionless. GPSA Engineering Data Book. (3) Once Ve is known, the minimum cross- sectional area required toavoid fluid erosion 2.5 Sizing Criteria for Gas/Liquid Two-Phase may determined be from the following Lines. derived equation: !ZDV UIbI a. Erosional Velocity. Flowlines, productionmani- folds, process headers and other lines transporting A = 9*35 + 21.25p Eq. 2.16 gas and liquid in two-phase flow should be sized Ve primarily on the basis of flow velocity. Experience where : has shown that loss of wall thickness occurs by a process of erosion/corrosion. This process is accel- A = minimum cross-sectional pipe flow erated by high fluid velocities, presence of sand, area required, in2/1000 barrels liquid corrosive contaminants such a s CO2 and H2S, and per day. fittings which disturb the flow path as such (4) Foraverage Gulf Coastconditions, T = elbows. 635”R, SI = 0.85 (35” API gravity oil) and Sg = 0.65. For these conditions, Figure 2.5 The following procedure for establishing an “ero- may be used to determine values of A for sional velocity” can be used where no specific essentially sand free production. The mini- information as to the erosive/corrosive properties mum required cross-sectional area for two- of the fluid is available. phasepipingmaybedeterminedbymul- tiplying A by the liquidflow rate expressed (1) The velocity above which erosion may occur in thousands of barrels per day. can be determined by the following empiri- cal equation: b. Minimum Velocity. If possible, the minimum velocity in two-phase lines should be about 10 feet per second t o minimize slugging of separa- v, =c Eq. 2.14 tionequipment.Thisisparticularlyimportant mñ in long lines with elevation changes. where: c. Pressure Drop. The pressure dropin a two-phase steel piping system may be estimated using sim-a V, = fluid erosional velocity, feet/second plified Darcy equation from the GPSA Engineer- ing DataBook (1981 Revision). C = empirical constant 0.000336f W2 AP Eq. 2.17 di5 Pm pm = gas/liquid mixture density a t flowing where: pressure and temperature, lbs/ft3 A P = pressure drop, psi/lOO feet. Industry experience to date indicates that for di = pipe inside diameter, inches solids-free fluids values of c = 100 for continuous f = Moody friction factor, dimensionless. service and c = 125 for intermittent service are pm = gas/liquid density a t flowing pressure conservative. For solids-free fluids wherecorrosion and temperature, lbs/ft3 (calculate as is not anticipated or when corrosion is controlled shown in Equation 2.15). by inhibition or by employing corrosion resistant alloys, values of c = 150 to 200 may be used for W = tota1 liquid plus vapor rate, lbs/hr. continuous service: values up to 250 have been The use of this equation should be limited to a used successfully for in€ermittentservice. If solids 1q.h pressure drop due to inaccuracies associated production is anticipated, fluidvelocities should be with changes in density. significantly reduced. Different values of “C” may If the Moody friction factor i s assumed to be an be used where specificapplication studies have average of 0.015 this equation becomes: shown them to be appropriate. Es. 2.17a Wheresolidsand/orcorrosivecontaminants are . . present or where “c” values higher than 100 for W may be calculated using the following derived continuous service are used, periodicsurveys to equation: assesspipewallthicknessshould be considered. The design of any piping system where solids are + W = 3180 Qg S g 14.6 QI SI Eq. 2.18 anticipated should consider the installation sand of where: probes, cushion flow tees, and a minimum of three Qg = gas flow rate, millioncubic feet/day feet of straight piping downstream of choke outlets. (14.7 psia and 60°F). (2) The density of the gas/liquid mixture may Sg = gas specific gravity (air = 1). becalculatedusingthefollowingderived QI = liquid flow rate, barrels/day. equation : S1 = liquid specific gravity (water = 1). 12409S1P+ 2.7 RSgP I t should be noted this pressure drop calculation is I Pm = + 198.7P RTE Eq. 2.15 ait estimate only.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 25. A P I R P * 1 4 E 91 m 0732290 0099506 4 m 24 Petroleum American Institute [: I W a 4 Y W ¿ñ [: I n CT ui CT S k 3 o v) O O v) r W tr a c3 z 4 5 [: I CT W a i O E! w a a GAWLIQUID RATIO, FTB/BARRELCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 26. A P I RPPL4E 91 m 0732290 0099507 b m RP 14E:Offshore Systems Production Piping Platform 26 2.6 Pipe Wall Thicknesses. The pipe wall thickness 2.8 Expansion and Flexibility. Piping systems may required for a particular piping service is primarily a be subjected to many diversified loadings. Generally, function of internal operating pressurs and tempera- onlystressescausedby (1) pressure, ( 2 ) weight of ture. The standards under which pipe is manufactured pipe,fittings,and fluid, (3) external loadings,and permit a variationin wall thickness below nominal wall ( 4 ) thermalexpansionaresignificantinthestress thickness. It is usually desirable to include a minimum analysis of a pipingsystem,Normally,most pipe corrosion/mechanical strength allowance of 0.050 inches movement will be due to thermal expansion. for carbon steel piping. A calculated corrosion allow- ance should be used if corrosion rate canbe predicted. a. A stress analysis should be made for a two-anchor (fixed points) system if the following approximate a. Thepressuredesignthicknessrequiredfora criterion from ANSI B31.3-1980 is not satisfied: particular application may be calculated by the following equation from ANSI B31.3:I t= PI Do Eq. 2.20 I where: + 2 (SE Pry) Eq. 2.19 where: t = pressure design thickness, inches; D = nominal pipe size, inches. = minimum wall thickness minus corrosion/ AI = expansion to be absorbed by pipe, mechanical strength allowance or thread inches (See equation 2.21). allowance (See ANSI B31.3) U anchordistance, (straight feet line Pi = internal design pressure, psig. distance between anchors), Do = pipe outside diameter, inches. L = actual length of pipe, feet. E = longitudinal weld joint factor (see ANSI AI may be calculated by the following equation B31.3) ; from ANSI B31.3-1980. = 1.00 for seamless; AI = 12LBAT2.21 Eq. 1 = 0.85 for ERW, Y = temperature factor (0.4for ferrous mate- where:I rials at 900’F or below when t<D/6). S = allowable stress in accordance with ANSI AI = expansionto inches. be absorbed by pipe, B31.3, psi. L = actual length of pipe, feet. b. Themaximumallowableworkingpressuresfor B = mean coefficient of thermal expansion most of the nominalwallthicknessesin sizes 2 at operatingtemperaturesnormally inch through 18 inch are given in Table 2.5 for encountered(Approximately 70 x . ASTM A106, Grade B, seamlesspipe,usinga 10“ inches/inch/”F for carbon steel corrosion/mechanical strength allowance of 0.050 pipe; for an exact number see ANSI inches. The maximum working pressures in Table B31.3). 2.5 were computed from Equation 2.19, for values of t < D/6. For values of t > D/6, the Lam6 equa- A T = temperature change, “F tion from ANSI B31.3 was used. Table 2.5 consid- b. The following guidelines may help in screening ers internal pressure and temperature only. These wall thicknesses may haveto be increased in cases piping or systems that generally will not require of unusualmechanical or thermalstresses.The stress analysis: maximum allowable working pressure of stainless (1) Systems where the maximum temperature steel tubing may be calculatedusingEquation change will not exceed 60°F. 2.19 withacorrosion/mechanical strength allow- (2) Piping where maximum the temperature ance of zero. change will not exceed 75”F, provided that c. Small diameter, thin wall pipe is subject to fall- thedistancebetweenturnsinthepiping Ure from vibration and/or corrosion. In hydro- exceeds 12 nominal pipe diameters. carbon service, pipe nipples 3/a inch diameter or smallershould beschedule 160 minimum; all c. ANSI B31.3-1980 does not require a formal stress pipe 3 inch diameter or smaller should be sched- analysis in systems which meet one of the follow- ule 80 minimum.Completelythreadednipples ing criteria: should not be used. (1) The systems are duplicates of successfully 2 7 Joint Connections. Commonly accepted methods . operatinginstallations or replacements of for makingpipe joint connections include butt welded, systems with a satisfactory service record. socket welded, and threaded and coupled. Hydrocar- (2) Thesystemscan be judged adequate by bon piping 2 inch in diameter and larger and pres- comparisonwithpreviouslyanalyzedsys- surized utility piping 3 inch in diameter and larger tems, should be butt welded. All piping 1% inch or less in d. Pipemovementcan behandled expansion by diameter should be socket welded for: bends(including“LoopdJ, “U”,“L”, and “Z” a. HydrocarbonserviceaboveANSI 600 Pressure shaped piping), swivel joints or expansion bel- Rating. lows. Expansion bends are preferred when prac- b. Hydrocarbon service above 200°F. tical. If expansion are practical; bends not swivel joints should be used. Swivel joints may c. Hydrocarbon service subject to vibration. be subject t o leakageandmust be properly d. Glycolservice. maintained. Expansion bellows may be subject Occasionally, it may not be possible to observe the to failure if improperly installed and should be guidelines given above, particularly when connecting avoided inpressurepiping.Expansion bellows to equipment. Inthis case, the connection maybe are often usedinengineexhaustsystemsand threaded or threaded and seal (back) welded. Threads other low pressure systems. should be tapered, concentric with the pipe, clean cut 2 9 Start-up Provisions.Temporary start-up cone . with no burrs, and conform to API STD SB or ANSI type’ screens should provided be in all pump and B2.1. The inside of the pipe on all field cuts should be compressor suction Screens lines. (with the cone reamed.ThreadcompoundsshouldconformtoAPI pointed upstream) should located be as close a s Bulletin 5A2. possible t o theinletflanges,withconsiderationforCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 27. A P I RP*14E 91 m 0732290 0099508 8 m 26 American Petroleum Institute I later removal. Sometimes a set of breakout flanges c. Hugley, Dale, “Acceleration Head Values are are required the wrnove to screens.screens The Predictable But-(not commonly from accepted should be checked during start-up and removed when formulae) ”, Petroleum Equipment and Services, sediment is no longer beinn collected. Caution should (March/ADril 1968). ” be exercised in screen sèíection and use to avoid d. Miller, J. E., “Experimental Investigation of creatingNPSH problems. Considerationshould be PlungerPump SuctionRequirements”,Petro- given to the need for small valves required for hydro- leumMechanicalEngineeringConference, LOS static test, vent, drain and purge, Angeles, California, September 1964. 2.10 References. e. TubeTurnsCorporation,“LineExpansionand Flexibility”, Bulletin TT 809, 1966. a. Crane Company, “Flow of Fluids Through Valves, Fittings, and Pipe”, Technical PaperNo. f. Tuttle, R. N., “Selection of Materials Designed 410. Copyright 1967. for Use in a Sour Gas Environment”, Materials Protection, Vol. 9, No. 4 (April 1970). b. Hugley, f‘Acceleration Dale, Effect is Major Factor Feed in Pump System”, Petroleum Equipment and Serutces, (JanuaryJFebruary 1968).COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 28. A P I R P * l 4 E 91 W 0732290 0099509 T m RP 14E:Offshore Production Platform Piping Systems 27I TABLE 2 6 . MAXIMUM ALLOWABLE WORKING PRESSURES PLATFORM PIPING ASTM A106, GRADE B, SEAMLESS PIPE - (STRESS VALUESfrom ANSI B31.3 - 1980) 1 2 3 4 6 6 7 8 9 10 Nominal ALLOWABLE MAXIMUM WORKING Weight NominalWall Outside Nominal -PSIG Size Diameter Thickness Foot Weight Schedule, L InIn In Lb Class NO. -20/400"F401/600"F601/600"F601/660"F 2 2.376 0.218 6.02 xs 80 2489 2362 2163 2116 0.344 7.46 - 160 4618 4364 3994 3926 0.436 9.03 xxs - 6285 6939 6436 6342 2 ?h 2.876 0.276 7.66 xs 80 2814 2660 2434 2392 0.376 10.01 - 160 4194 3963 3628 3666 0.562 13.70 xxs - 6860 6473 6925 6822 0.760 17.02 - - 9772 9423 8625 8476 3 3.600 0.300 10.25 xs 80 2653 2412 2208 2170 0.438 14.31 - 160 4123 3896 3666 3604 0.600 18.68 XXS - 6090 6765 6268 6176 4 4.600 0.237 10.79 STD 40 1439 1360 1246 1223 0.337 14.98 xs 80 2276 2161 1969 1934 0.438 18.98 - 120 3149 2976 2724 2676 0.631 22.62 - 160 3979 3760 3442 3382 0.674 27.64 xxs - 6307 6015 4691 4611 I 1206 1139 1043 1026 6 6.626 0.280 18.97 STD 40 0.432 28.57 xs 80 2062 1949 1784 1763 0.562 36.42 - 120 2817 2663 2437 2396 0.719 46.34 - 160 3760 3663 3262 3196 0.864* 63.16 xxs - 4660 4404 4031 3961 8 8.626 0.277 24.70 - 30 908 868 786 772 0.322 28.65 STD 40 1098 1038 950 934 0.406 36.66 - 60 1467 1377 1260 1238 0.600 43.39 xs 80 1864 1762 1612 1684 0.594 60.93 - 100 2278 2163 1970 1936 0.719 60.69 - 120 2838 2682 2466 2413 0.812* 67.79 - 140 3263 3084 2823 2774 0.876* 72.42 xxs - 3666 3369 3076 3022 0.906* 74.71 - 160 3700 3496 3200 3146 10 10.760 0.260 28.04 - 20 636 601 650 641 0.279 31.20 - - 733 693 634 623 0.307 34.24 - 30 827 781 716 703 0.365 40.48 STD 40 1023 967 886 869 0.600 64.74 xs 60 1486 1403 1284 1262 0.694 64.40 - 80 1811 1712 1667 1640 0.719 77.00 - 100 2262 2128 1948 1914 0.844* 89.27 - 120 2700 2662 2336 2296 1.000* 104.13 XXS 140 3271 3091 2829 2780 1.125* 116.66 - 160 3737 3631 3232 3176 .*All welds must be stress relieved. NOTE: Includes CorrosionlMec~lan~cal strength allowance0.050 inches and lag96 variation belmu nominal wall of tiLiclcness (Manvfactwer tolerance). 1 COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 29. 1 A P I R P * 3 4 E 7 1 W O732270 O077530 b 28 Institute TABLE 2.5 (Continued) - 1 2 3 4 . 6 6 7 8 9 10 Nominal Weight Nominal ALLOWABLE MAXIMUM WORKING Outside PRESSURES - Wall Nominal Per -PSIG Diameter Size Thickness Foot Weight Schedule(-- * In In In 401/600"F -20/400"F Lb NO. 601/660"F 601/600"F Class 12 12.750 0.260 33.38 20 636 606 463 456 0.330 43.77 30 760 719 668 646 0.375 49.66 - 888 839 768 765 0.406 63.66 40 976 923 846 830 0.600 66.42 - 1246 1177 1078 1059 0.562 73.22 60 1426 1347 1233 1212 0.688 88.57 80 1794 1696 1662 1626 0.844* 107.29 100 2268 2133 1963 1919 1.000* 126.49 120 2730 2579 2361 2320 1.126* 139.68 140 3114 2943 2694 2647 1.312* 160.33 160 3700 3496 3200 3146 14 14.000 0.260 36.71 10 487 460 421 414 0.312 46.68 20 646 610 668 649 0.375 64.57 30 807 763 698 686 0.438 63.37 40 971 917 840 826 0.600 72.09 - 1132 1070 979 962 0.694 86.01 60 1379 1303 1193 1172 0.760 106.13 80 1794 1696 1662 1525 0.938* 130.79 100 2304 2177 1993 1958 1.094* 160.76 120 2734 2684 2366 2324 1.260" 170.22 140 3171 2997 2743 2696 1.406* 189.16 160 3616 3417 3128 3074 16 16.000 0.260 42.06 10 426 402 368 362 0.312 62.36 20 664 633 488 479 0.375 62.68 30 706 666 610 699 0.500 82.77 40 988 934 866 840 0.666 108.00 60 1346 1271 1164 1143 0.843* 137.00 80 1780 1682 1540 1613 1.031* 166.00 100 2226 2103 1926 1891 1.218* 193.00 120 2676 2628 2314 2274 1.437* 224.00 140 3212 3036 2779 2731 18 18.000 0.260 47.39 10 378 367 327 321 0.312 69.03 20 601 473 433 426 0.376 70.69 - 626 691 641 632 0.438 82.06 30 762 710 660 639 0.600 93.45 - 876 828 768 745 0.662 106.00 40 1001 946 866 861 0.718 133.00 60 1319 1246 1141 1121 0.937* 171.00 80 1771 1674 1632 1606 1.166* 208.00 100 2232 2109 1931 1897 1.343* 239.00 120 2632 2487 2277 2237 G Ï welds must be stress relieved.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 30. A P I RP*34E 91 M 0732290 0099533 B m RP 14E:OffshoreProductionPlatform Piping Systems 29I SECTION 3 SELECTION OF VALVES 3.1 General. Ball, gate,plug,butterfly,globe,dia- b. Gate Valves. Gate valves are suitable for most phragm, needle, and check valves have all been used in on-off, non-vibrating hydrocarbon utilities or platform production facilities. Brief discussions of the service for all temperature ranges. In vibrating advantages, disadvanfages and design features for each service,gatevalvesmay moveopen or closed type of valve are given below. Based on these considera- from theirnormal positionsunless stem the tions, specific suggestions for the applicationof certain packing is carefully adjusted. Gate valves have types of valves are given in the following paragraphs. better torque characteristics than ball or plug Valve manufacturers and figure numbers,acceptable to valves but do not have the easy operability of a particular operating company, are normally given by quarter turn action. valve ty e and size in Pipe, Valves, andFittings (1) In sizes 2 inch and larger, manually oper- Tables gee Appendix C). Whenever possible, several ated gate valvesshouldbeequippedwith different acceptable valves shouldbe listed in the Pipe, flexible discs or expanding gates. Valves, and Fittings Tables to provideachoice of valve manufacturers. Valve catalogs contain design fea- (2) Gate valves with unprotected rising stems tures, materials, drawings and photographs of the var- are not recommended since the marine en- ious valve types. vironmentcancorrodeexposedstemsand threads, making the valves hard to operate a. As a general guideline, operated lever ball and damaging stem packing. valves plug and valves should be provided (3) Reverse-actingslabgatevalvesaresuit- with manual gear operators as follows: able for automatic shutdown service. Wi€h ANSI 150 lb through400 lb .-.AO inch and larger thesevalves, simplepush-pulloperators ANSI 600 lb and900 lb _..___._.__.___ 6 inch and larger can be used, thus avoiding the complicated levers cams and normally required with ANSI 1600 lbandhigher 4 inch larger and ball orplug valves.Allmoving parts on b. As a generalguideline the following valves gate valveswithpoweroperatorscan be should be equipped with power operators: enclosed, eliminatingfouling by paintor (1) All shutdown valves. corrosionproducts. (2) Centrifugal compressor inlet and discharge (4) Gate valves should not be used for throt- valves.Thesevalvesshouldcloseautoma- tling service.Throttling,especiallywith tically on shutdown of the prime mover. fluids containing sand, can damage the seal- ing surfaces. (3) Divert, blowdown and automatic other valves. c. Plug Valves. Plugvalvesaresuitableforthe (4) Valves of the following sizes, when fre- sameapplications as balrvalves(seeSection quently operated: 3.2.a), and are also subject to similar tempera- ture limitations. Plug valves are available with ANSI 150 lb _____ __________ 16 inch and larger quarter turn action in either lubricated or non- ANSI 300 lband 400 lbinchandlarger lubricated designs, Lubricated plug valves must ANSI 600 lb and 900 lb 10 inch and larger be lubricated on a regular schedule to maintain ANSI 1500 lb and h i g h e r ~ inch and larger 8 a satisfactory seal and ease of operation. Fre- quency of lubrication required depends on type 3.2 Types of Valves. of service. The lubrication feature does provide a remedial means for freeing stuck valves. In a. BallValves.Ball valves are suitable for most the non-lubricateddesign,thesealis accom- manual on-off hydrocarbonorutilitiesservice plished by Teflon, nylon or other “soft” material. when operating temperatures a r e between They do not require frequent maintenance lubri- -20°F 180°F. and Application of ball valves cation but may be more difficult to free after above 180°F should be carefully considered due prolonged setting in one position. The applica- to the temperature limitations of the soft seal- tion circumstance will generally dictate a selec- ing material. tion preference based on these characteristics. (1) Ballvalves are availableinbothfloating ball and trunnion mounted designs. Valves d. Butterfly Valves.RegularButterfly valves are of the floating design, ball develop high suitablefor course throttlingandothera plica- operating torques in high pressure services tions where a tight shutoff is nót required: I t is orlargediametersbuttendtoprovide a difficult to accomplishaleak-tightsealwitha better seal. Trunnion mounted ball valves regular (non-high performance)butterfly valve. turn more easily but may not seal as well. They are not suitable as primary block valves for Thus, a trade-off decision is required to vessels, tanks, etc. Where a tight seal is required, select the proper type for each application. use a high performance valve or limit the valve to (2)Ballvalves are not suitabIe for throttling low differentialpressure and low temperature because, in the partially open position, seal- (150’F) service. Because low torque requirements ing surfaces on the exterior of the ball are permitbutterflyvalves to vibrate open,handles exposed to abrasion by process fluids. withdetents should be specified. (3) I n criticalservice,considerationshouldbe e. GlobeValves.Whengood throttlingcontrolis given to purchasing ball valves with lubri- required (e.g., in bypass service around control cation fittings for the ball seats, as well as valves), globe valves are the most suitable. for the stem, since lubrication is sometimes necessary to prevent minor leaks or reduce f. Diaphragm (Bladder) Valves. Inthis valve operatingtorques.Ifa double block and design, a diaphragm made of an elastomer is bleed capability is desired, a body bleed connected to the valve stem. Closure is accom- port independent of the lubrication fittings plishedbypressingthediaphragmagainst a should be provided. metal weir which is a part of the valve body. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 31. A P I R P 8 1 4 E 91 m 0732290 0099532 T m 30 Institute Petroleum American Diaphragmvalvesareusedprimarilyfor low inliquidserviceunless the orifice inthe pressure water (200 psig or less) service. They piston is changed. are especiallysuitableforsystemscontaining appreciable sand or other solids. 3.3 ValveSizing. Ingeneral,valvesshouldcorre- spond to the size of the piping in which the valves g. Needle Valves. Needle valves are basically are installed. Unless special considerations require a miniature globe valves.They are frequently full opening valve(sphere launching or receiving, used forinstrumentandpressuregage block minimum pressure required, drop meter proving, valves; for throttling small volumes of instru- pump suction, etc.),regular port valves are acceptable. ment air, gasorhydraulicfluids;andforre- ducing pressure pulsations in instrument lines, a. The pressure across drop avalve in liquid The small passageways through needle valves servicemay be calculatedfromthefollowing are easily plugged, this and should be con- (Fluid Controls Institute) equation: sidered in their use. h. Check Valves. Check valves are manufactured in E .3 1 q . avariety of designs,includingswingcheck,lift plug, ball, piston, and split disc swing check. Of where: these, a full opening swing check is suitable for most non-pulsating applications. Swing checks can A p = pressure drop, psi. be used in verticalpiperuns (with flowin the GPM = liquid flow rate, gallons/minute. upward direction) only if a stop is included to pre- C, = valvecoefficient (GPMwater flow, at vent clapper the from opening past top-dead- 60"F,acrossvalve with a pressure center.Swingchecksshouldneverbeusedina drop of 1psi). downwarddirectioninaverticalpipingrun. If usedwherethere is pulsating flow or lowflow SI = liquidspecific gravity (water = 1). velocities, swingcheckswill chatterand eventu- b. For a valve in gas service, the following (Fluid ally thesealingsurfaces will bedamaged.The Controls Institute) equation may be used: clapper may be faced with Stellite for longer life, To minimize leakage through the seat, a resilient Ap = 941 (Q L) Eq. 3.2 sealshould used. be Removable seatsarepre- C" ferred, since they make repair of the valve easier where: and also facilitate replacement of the resilient seal in the valve body. Swing check valves should be A p = pressure drop, psi. selected with a screwed or bolted bonnet to facili- S g = gas specific gravity (air = 1). tate inspection or repair of the clapper and seats. In many cases, for a high pressure swing check to T = flowing temperature, "R. be in-line repairable,theminimum sizemay be P = flowing pressure, psia. two and one half or three inches. Qg = gas flow rate, million cubic feet/day (1) Swing check valves in a wafer design (14.7 psia and 60°F). (which saves space) are available for instal- CV = valve coefficient (GPMwater flow, at lation between flanges. This type of check 60"F, across valve with a pressure drop valve is normally fullnot opening, and of 1psi). requires removal from the line for repair. (2) The split disc swing check valve is ä vari- C. Values ofCv are usually published in valve cata- ation of the swing check design. The springs logs. In calculating the overall pressure drop in a used to effectclosuremaybesubjectto piping system, it is common practice to add the rapid failure due t o erosion or corrosion. equivalent length of valves t o the length of straight pipe.Valve manufacturers usually pub- (3) Lift plug check valves should only be used lish data on their valves, either directly in terms in small, high pressure lines, handling clean of Equivalent Length of Straight Pipe in Feet, or fluids. Lift D ~ U Pvalv.es can be designed for aslength/diameterratios. If suchdataare not useineitherEorizontal or verticil lines, available for a particular valve, approximate but the two are not interchangeable. Since values may be read from Table 2.2. Block valves lift plug valves usually depend on gravity and bypass valves, used in conjunction with con- for operation, they may be subject to foul- trol valves,shouldbesizedinaccordancewith ing by paraffin or debris. API RP 550. Ball check valves are very similar to lift plug check valves. Since the ball is lifted 3.4 Valve Pressure Temnerature and Ratings. by fluid pressure, this type check valve does Steel valves are manufactured in aicordance with AFI not have atendency to slam as does a swing Std 600, API Std 602, API Spec 6A, API Spec 6D or checkvalve. It is thereforepreferablein ANSI B16.5-1981. The API specificationscover com- sizes2inchorsmallerforcleanservices plete manufacturingdetails, ivhile ANSI B16.5-1981 that have frequent flow reversals. covers pressure-temperature ratings and dimensional details. Pistoncheckvalvesarerecommendedfor pulsating flow, such as reciprocating com- a. Most steelvalvesusedin platformfacilities are pressor or pump discharge lines. They are designated ANSI and are designed to the pressure- not recommended for sandy or dirty fluid temperatureratingsforsteel pipeflangesand service.Pistoncheckvalves are equipped flanged fittings given in ANSI B16.6. Face-to-face with an orifice to control the rate of move- and end-to-end dimensions steel for valves are ment of the piston. Orifices used for liquid covered in ANSI B16.10. The allowable working services are considerablylargerthanori- pressure for an ANSI B16.5-1981, an API 600, an fices for gas services. A piston check valve API 602 or an API 6D valve is a function of the designed for gas service should not be used operating temperature.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 32. A P I RP*14E 91 H 0732290 0099513 L m RP 14E: Offshore Production Platform Piping Systems 31I b. Steel valves built to API Spec 6A are used pri- AISI 316L, for corrosion resistance and easeof marily on wellheads and flowlines. API 6A valves operation. are designated API 2000, 5000, 3000, €0,000, 15,000and20,000.TheAPI 6A designation (4) Resilientsealingmaterialsusedinvalves numerically denotes the allowable working pres- Include Buna N,Neoprene,Delrin,Viton, sure for temperature between -20’F and 250°F. It Teflon,Nylonandtetrafluoroethylene shouldbecautioned that although API 6A and (TFE) . Resilient sealing materials should ANSI B16.5 flanges are similar dimensionally, be carefully selected to be compatible with they are fabricated from different materials and the processfluids and temperatures. consequently have different pressure ratings, cor- rosion resistance and weldability. b. Corrosive Service. c. Cast iron valves are designed in accordance with (1) Generally, carbon steel valve bodies with cor- ANSI B16.1 and, in sizes 2 inch through 12 inch, rosion resistant internal trim are used for cor- are rated for either 125psi saturated steam or 200 rosive service. AISI 410 type stainless steel is psi cold water (nonshock). Steel valves are recom- generallyusedforinternaltrim.Austenitic mended for hydrocarbon service. stainless steels, such as AISI 316 and higher alloys may also be used for internal trim. d.The allowable workingpressuresandtempera- tures described above consider the metalvalve (2) For lowpressure (200 psig or lower) salt water parts only. For valvesutilizingresilientsealing services, butterfly valves ductile with iron materials, the maximum allowable operating body, aluminum-bronze disc, and AISI 316 temperature is normally limited by the resilient stainlesssteelstemwithBuna N seals are material. The maximum permissible temperatures satisfactory. Gate valves in this service should forvalves are indicated valvein catalogs and beiron body bronze trim (IBBM). For high should be included in the Pipe, Valves, and Fit- pressure (above 200 psig) salt water applica- tings Tables described inAppendix C. tions, steel gate valves with aluminum-bronze trim give good service. 3.6 Valve Materials. c. Chloride Stress Cracking Service. Consideration a. Non-Corrosive Service. should be given to chloridestress cracking when (1) For non-corrosive services, carbon steel meet- selecting trim materials, see Paragraph 1.7.d. ing the requirements of API 600, API 6A, APT d. SulfideStressCrackingService. Valve bodies 6D, or ANSI B16.5-1981 is satisfactory for andinternaltrim shouldbeinaccordance with valve bodies because of its strength, ductility NACE MR-01-75 or constructed of materials which and resistance to damage by fire. can bedemonstrated to be resistant tosulfide (2) Cast or ductile iron valve bodies should not be stress cracking in the environment for which it is usedforhydrocarbon or glycol services be- proposed. cause of their low impact properties. Non- 36 References. . ferrous valves are not suitable for process hydrocarbon service because theymay fail in a a. CameronHydraulicData Handbook, Ingersoll- fire: they may be suitable for instrument and Rand Company. control system service. Cast iron, ductile iron, b. Chemical Engineering-Deskbook Issue, “Valves”, and bronze body valves may be used for water October 1 , 1971. 1 services. c. Evans, Frank L., “Special Report on Valves”, (3) One-half inchandsmallerneedlevalvesfor Hgdrocarbon Processing, Vol. 40, No. 7 (July process hydrocarbon serviceshould be aus- 1961). teniticstainlesssteel,suchasAISI 316 or d. Fluid Controls Institute, Bulletin FCI 62-1, COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 33. A P I RPx14E 9 1 m 0732290 0099514 3 W 32 Petroleum American Institute SECTION 4 FITTINGSANDFLANGES 41 General.Welded,screwed . andflangedpiping 4.3 ScrewedFittings. Whenscrewed fittings *are connections areallacceptable foruseinplatform permitted by Section 2.7, forged steel screwed fittings piping within the application limitations discussed in should be used for both hydrocarbon and utility service the following sections.Only carbon steel materials are to reduce the possibility of accidentalmisapplication. discussed since carbon steel is suitable for the pre- Forgedsteel screwed fittings are normallymanufac- ponderance of platform piping systems. The operator tured of ASTM A105 steel in 2000, 3000, and 6000 lb should select other materials, if needed, on an engi- ratings to ANSI B16.11. neering basis (See Section 1.1). 4.4 Branch Connections. a. Many of the fittings and flanges described in this a. Branchconnectionsinweldedlinesshouldbe section are manufactured using materials in butt weld straight tees or reducing tees when accordance with ASTM A105. In general, ASTM the branch line is 2 inch nominal pipe size or A105 does not require heat treatment (normaliz- larger, and is equal to or greater than one half ing) for piping components (flanges, fittings and of the nominal run size, If the branch line is 2 similar parts) 4 inchnominalpipesizeand inch nominal pipe size or larger, but less than smaller,except for ANSIflangesabove 300 lb one half of the nominal run size, welded nozzles primary service rating. may be used. Branch lines 1% inch nominal pipe b. Fittings and flanges that do not require normaliz- size and smaller should be connected to runs 1% ing in accordance with ASTM A105 due to size or inchnominaland smaller,with socketweld tees, pressure rating, should be normalized when used and to runs 2 inch nominal and larger with socket- for service temperatures below 30°F. Fittings and weld couplings or equivalent. Table 4.1 illustrates fla5ges in this category should be marked HT, the provision of the paragraph. N, , or withsome other appropriate markmg to b. Stub-in connections should generally not be used designate normalizing. (SeeParagraph 4.9, Reference c).Thedisad- vantages of an unreinforced stub-in connection 4.2 Welded Fittings. Material for butt weld fittings are numerous. Sharp changes section in and should be seamless ASTM A234, Grade WPB. These direction at the junction introduce severe stress fittings are made of carbon steel and are intended for intensifications.Reinforcementusing a pad or use with Grade B pipe. Unless the purchaser clearly a saddle improves the situation somewhat;how- specifies that the fittings shall be seamless, fittings ever, finished the connectionis difficult to with welded seams may be furnished a t t h e manu- examine welding other for and defects. The facturers option. likelihood thatstress-intensifyingdefectswill escapedetectionmakestub-ins a poor choice a. Dimensions and tolerances for butt weld, long- for critical services or those with severe cyclic radius elbows andteesare coveredbyANSI operating conditions or loadings. If stub-in con- B16.9. Short radius butt weld elbows are covered nections are necessary, the use of full encircle- by ANSI B16.28. If space permits, long radius ment saddles is recommended. elbowsshould be used in platform piping sys- tems.Shortradiuselbows are subject to high c. Branchconnectionsinscrewedpipingsystems stress concentrations in the throat of the sharp should be made using straight tees and swage curvature bend, and should be derated to 80 reducers, or reduced outlet tees. All screwed pip- percent of the calculatedallowable working ingsystems should be isolatedfrom welded - pressure if subject to pulsation or vibration. piping systems by block valves. b. ANSI B16.9 requiresthatthepressurerating 4.5 Flanges. of steel butt weld fittings be equal to that of . seamless pipe of the wall same thickness. Butt a. General.Weldingneckflangesshouldbeused weld fittings should, therefore, purchased with be for piping 2 inch and larger. Slip-on flanges are a wall thickness to match the pipeto which they not generally recommended. ANSI type flanges, will be connected, except when thicker wallsare manufacturedinconformancewithANSI requiredforshortradius elbowswhich have B16.5, are used in most applications. API type been derated as sutlined above. Otherwise, the flanges,manufacturedaccordingtoAPISpec pressure rating of the system will be limited by 6A, are used primarily near the wellhead. the lesser wall thickness in the fittings. If it is necessary to weld fittings or pipe with unequal (1) ANSI flanges are supplied in raised face (RF) wall thicknesses, procedure the outlinedin andring-typejoint{RTJ). RF flangesoffer Appendix B of this RP should be used to design Increased ease of mamtenance and equlpment the joint. replacement over RTJ. RTJ flanges are com- monly used in higher pressure service of ANSI c. Socket welding elbows and tees are manufactured 900 and above and may also be used for ANSI inaccordancewithANSI B16.11. Normally, 600 in piping systems subjectto vibrating serv- ASTM A105steelforgings are used. Bar stock ice. RTJ flanges should also be considered for meetingtherequirements of ANSI Bl6.1: may serviceswithspecial temperature or hazard alsobeused. I t shouldberequwed that flttlngs problems. When RTJ flanges are used, the pip- machined from bar stock may not havethe forging ing configuration should be designed to allow flow lines parallel with the axis of the fittings. component removal since additional flexibility Socket welding fittings are suppliedin pressute is required to remove the ring gasket. Mate- class designations of 3000, 6000, and 9000 lb non- rials for ANSI flanges are normally manufac- shock WOG (water, oil, gas). turedinaccordancewithASTMA-105. Flanges manufactured in accordance with d. The pressure drop due towelded fittings may be ASTM A-181 may be suitable for certain non- calculated by including their equivalent length critical services, e.g., water or atmospheric in the total length the piping system. Equiva- of drains. lentlengthsfor weldedelbows andteesare included in Table 2.2. ASME Sect. VIII, Div. I, Part UWCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 34. APRP*34E I 93 m 0732290 0099535 5 m RP 14E: Offshore Production Platform Piping Systems 33 TABLE 4.1 BRANCHCONNECTION SCHEDULE-WELDEDPIPING 15 42 3 6 7 8 9 10 12 11 15 14 13 16 NOMINAL BRANCH NOMINAL RUN SIZE (inches) SIZE (inches) X 1 2 1% 2% 3 4 6 8 10 12 14 16 18 M SWTSWT SWTSWT 6SC 6SC 6SC 6SC 6SC 6SC 6% 6SC 6SC 6SC 6SC X SWT SWT SWT SOL 6SG 6SC 6SC 6SC 6SC 6SC 6% 6SC 6SC 6SC 1 SWT SOL 6SC 6SCSOL 6SC 6SC 6SC 6SC 6SC 6SC SOL 1% 6SC 6SC TR 6SC SOL 6SC 6SC SWT 6SC SOL SOL 6SC 2 RT RT RT T WOL WOL WOL WOL WOL WOL WOL 2% TRT RT WOL WOL WOLWOL WOL WOL WOL 3 RT T RT WOL WOL WOL WOL 4 RT T RT WOL WOL WOL WOL WOL 6 RT RT WOL T RT WOL WOL 8 RT RT RT T RT WOL RT 10 RT RT T RT 12 RT RT T RT - 14 RT T RT 16 T RT 18 T Legend T-Straight Tee (Butt Weld) RT-Reducmg Tee (Butt Weld) TR-Straight Tee and Reducer or Reducing Tee WOL-Welded nozzle or equivalent (Schedule Branch Pipe) of SOL-Socketweld couplings or equivalent-6000# Forged Steel SWT-Socketweld Tee 6 S C 6 0 0 0 # Forged Steel Socketweld Coupling (x inch and smaller threadbolts or screwed couplings may be used for sample, gage, test connection and instrumentation purposes) (2) Materials for API flanges are specified in APT I carbon and steam services. Use of graphite or Spec 6A. Some API material types require otherasbestos substitutes other for services specialweldingprocedures. API flanges are should be preceded by service-specific studies. availablein 2000, 3000, 5000, 10,000, 15,000 and 20,000 psi pressure ratings. maxi- The (2) Ring gasketsfor API and ANSI RTJ mum working pressure ratings are applicable flanges manufactured are in accordance for temperatures between-20°Fand 250F. with API Spec 6A. API ring-joint gaskets API flanges rated 2000, 3000 and 5000 psi are are made of either iron,soft low-carbon designated API Type 6B, and require Type R steel, AISI 304 stainless steel or AISI 316 or RX gaskets; 10,000, 16,000, and 20,000 psi stainless steel. Unless otherwise specified ratingsaredesignated API Type 6BX and by the purchaser, ring-joint gaskets made require BX ring gaskets. API Type 6B flanges of soft iron or low-carbon steelare cad- should have a full-face contour. API Type 6BX mium-plated. For ANSI and API Type 6l3 flanges shouId have a relieved-face contour. RTJ flanges,either API Type R or RX gaskets required. R are Typering-joint b. Gaskets. gaskets are made in either an octagonal or oval cross-section. Type RX ring-joint gas- (1) For ANSI raisedface(RF)flanges,spiral- kets pressure are energized .and havea wound asbestos gaskets stainless with steel modified octagonal cross-section.Type R windings should be used because of their and RX gaskets are interchangeable; how- strength and sealing ability. For flat face duc- ever, RX gaskets have a greater ring tile or cast iron valves used in water service, height so the distance between made-up full face compressed asbestos gaskets or arimid flangesisgreaterandlongerflangebolts or glassreinforcedelastomer bound gaskets are required. should be used. If less than full face gaskets (3) Typering-joint R gaskets of softiron are used on flat faces, flanges may be broken should be used in ANSI 600 lb and 900 lb as flange bolts are tightened. I gaskets con- f services.Type RX ring-joint gaskets of taining asbestos are unavailable or cannot be low-carbonsteelprovideabetterseal at used in a particular service, gasket other high pressure and should be used in ANSI materials are available. Flexible graphite sheet 1600 lb and higher and in API 2000, 3000 laminated s€ainless with steel reinforcement and 5000 lb services. and graphite filled spiral wound gaskets are (4) API Type 6BX flangesrequire API Type an acceptable alternate for asbestos for hydro- BX pressure energized ring gaskets. TheseCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 35. A P I RP*KL4E 91 m 0732290 0099536 7 m 34 Institute Petroleum American gaskets,made of low-carbonsteel,should 4.7 Special Requirements for Sulfide Stress Crack- beused for API 10,000, 15,000 and 20,000 ing Service. Fitting and flange materials, as normally lb flanges. manufactured, are generally satisfactory for sulfide c. Flange Protectors. Various methods (painting, stress cracking service with the additional stipulation wrapping with tape, etc.) have been tried to pro- that they be modified to conform t o the requirements tect gaskets, bolts and flange faces from corrosion; of NACE MR-01-75. ASTM A194, Grade 2M, nuts and none have been completely satisfactory. Potential ASTMA193, Grade B7M, bolts are generally satis- solutions include: (1) the use of soft rubber flange factory for pipe flanges, Consideration should also be protectors (300°F limit) which are installed when given to torque requirements dusing installation. Type the flange is made up; and (2) stainless steel or R and RX rings should be made of annealed AIS1 316 polymer bands with a grease fitting. For HzS stainless steel. service, the boIts should be left open to allow the wind to disperse any seepage. 4 8 Erosion Prevention. To minimize erosion where . d. Bolts and Nuts. For flanged pipingsystems, sandproductionisexpected,shortradiuspipeells stud bolts, threadedovertheirlengthinac- cordance with ASTM A193, Grade B7, or ASTM e, shoul not beused, All turns in flowlinesshouldbe made ith tees andweld caps (or blind flanges), cap tees or flow tees, or longradiusbends(minimum A354, Grade BC, shouldbeused.Nutsshould be heavy hexagon, semi-finished, in accordance bendingradiusshouldbeinaccordancewithANSI with ASTM A194, Grade 2H. Boltsandnuts B31.3). For a discussion of maximumvelocities to should protected be from corrosion;current minimize erosion, see Paragraph 2.S.a. methods include cadmium plating, hot-dip gal- vanizing, and resin coatings. 4.9 References. a.Assini,John,“WeldedFittingsandFlanges”, 4.6 Proprietary Connectors. Severalproprietary Southem E n g i n e e h g (Octobel. 1969). connectors are availablereplace to flanges. Such b. Canham, W. G., and Hagerman, J. R., “Reduce connectors are satisfactory if they sealing, have Piping Connection Costs”, Hydrocarbon Proces- strengthandfireresistantqualitiescomparableto sing (May 1970). flanges.Speciallymachinedhubsand ringgaskets are required on valves and fittings to mate with the e. Tube Turns Division of Chemetron Corporation, connectors. Alignment is critical. Piping Engineering Handbook (October 1969).COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 36. RP 14E:Offshore Production Piping Platform Systems 36I SECTION 5 DESIGNCONSIDERATIONS FORPARTICULAR PIPINGSYSTEMS 5 1 General. This section presents considerations for . the following provisions should be considered: flowschemes,pipinglayouts,andspecificdesign (1) Connections shouldbe arranged so the requirements for particular piping systems. exchangerbundlemaybepulledwithout h+ng to cut or weldon inlet and outlet 5.2 Wellhead Accessory Items. P1PWz. a. SamplingandInjection Connections. Connec- (2) On the flanged end of the shell, exchanger U- tions may be desired near the wellhead for chemi- bends, if used, should either be exposed to the cal injection and for obtaining samples (See Fig- exterior, or easily accessible for nondestructive Ures 5.1A and 5.1B). If installed, they should be testing. inch minimum nominal size and include a close- (3) Aflangedend heatexchangershell of a coupled bIock valve. Associated piping should be standard dimension i s desirable so bundles stainless tubing steel or heavy pipe wall and can be interchanged,or pulled and repaired. should be well protected to minimize the possibil- ity of damage. A spring loaded ball check valve (4) A relief system in accordance with Section 5.8 should be close-coupled to the block valve on in- should be provided. jection lines. d. Flowline Check Valve. A flowlinecheckvalve b. Chokes. Chokes are normally installed to control should be installed to minimize back flow due to the flow from oil and gas wells. Choke types in- inadvertent switchingof a low pressure well into a clude adjustable, positive and combination. The higher pressure system, or in case of line rupture. numberandlocation of chokesdependon the Provisionsshouldbe made for blowdown of the amount of pressure drop taken, well fluid, flow flowline segment between wellhead and check rate, and solids in the wellstream. Usually, if valve to facilitate periodic testing a t check valve. only one choke is used, i t should be located near See Section3.2.h for a discussion of check valves. the wellhead. Additional chokes may be located nearthe manifold, enteringlowtemperature e. Flowline Support. Flowlines should be supported separation units, in conjunction with line heat- and secured to minimize vibration and to prevent ers,etc.Thefollowinggeneralguidelines whip. See Section 6.4 for discussion of piping sup- should be considered regardless of the number ports. When designing flowline supports,it should of chokes or their location: be recognized that even though the wellhead may be fixed to the platform, there is a possibility of (1) Choke bodies should be installed in a man- independentwellhead movement due to wave ner that will permit easy removal and trim action, wind forces, etc., on the conductor. changes. (2) Thedownstream flow passagewithinten 5.4 Production Manifolds. nominalpipediametersshouldbefree of abrupt changes direction minimize in to a. General. For illustration purposes, Figures 5.1A flow cutting due to high velocity. and 5.1B show a six-header manifold. The actual (3) Outletconnectionsshouldbeexamined to number and function of headers depend upon the determine if theirboreshouldbetapered specific application. The pipe routing to the pro- to improve flow patterns. duction headers should be the shortest and least tortuous. Eachpart of the manifoldshould be (4)Suitableprovisionsshouldbeprovidedto designed to limit maximum velocity in accordance isolate and depressure the choke body when with Section 2.5.a. Fabricated components should changing trim, removing trash, etc. be stress relieved, if required, in accordance with ANSI B31.3. Provisions should be made to allow 5.3 Flowline and Flowline Accessories. When non-destructive testing of headers. Quarter turn designingflowlines,considerationshould be given to valves are preferred in manifold service for ease of pressure,temperature, velocity, erosive and corrosive operation. Above 6000 psig working pressure, only effects on the pipe, etc. (See Sections 2, 3 and 4). The gate valves are generally available. accessories discussed below may be used necessary. as .b.Manifold Branch Connections. Manifold branch a. Flowline Pressure Sensor. The installation of a connectionsshould be inaccordancewithTable flowline sensw should inbe accordance with 4.1. If Weldolets@are used, care should be taken API R P 14C. Further, the connection should be to ensure the entrance hole is smooth and free of ?h inchminimumnominalsizeandlocated to burrs after it is welded in place. The terminus of minimize the possibility of plugging and freez- the manifold runs should be blind flanged to pro- ing. Connections on the bottom of the line or in vide a ,fluid cushion area and for possible future turns should avoided. be Sensorsshouldbe expansion. installed with an external test connectionand c. ManifoldValveInstallation.Themanifold ar- blockvalve.Sensinglinesshouldbestainless rangementshouldprovideeasyaccesstoeach steelandsecuredtopreventwhipincase of valve operational for purposes easy and re- severance. moval. In initial design of the manifold, it may b. Flowline Orifice Fitting. A flowline orifice fit- be desirable to make provisions for the future ting, as shown on Figures 5.1A and 5.1B, may be installation of valve operators. desirable in gaswell service for eithera well mon- itoring aidor as a meansof production allocation. 6.5 Process VesselPiping. A typical three-phase vessel with standard accessories and process many c. Flowline Heat Exchanger. I a flowline heat f optional items is shown on Figure 5.2. Different vessels exchangerisused(SeeFigures 5.1A andS.lB), are required for different functions in processing: I COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 37. API R P * L 4 E 71 W 0732270 00775LB O W 36 Institute Petroleum AmericanCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 38. A P I RP*14E 91 m 0732290 0099519 2 mCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 39. A P I RP*LYE 91 m 0732290 0099520 9 W j 38 Institute Petroleum American however, all of the flow streams to and from a vessel b. FireWaterSystems.Firewater systems are are generally handled in a similar manner. All of the normally constructed of carbon steel pipe in items shown in Figure 6.2 may not be needed, but are accordance with Sections 2, 3 and 4. Special corro- shown in their recommended location whenrequired. sion resistant materials may be desirable. The fire Accessories should be installed to permit ready removal water system mayrequire sectionalizing valves forrepairs or replacement.Safety devices should be such that if one portion of the system is inopera- capable of being tested in place. ble, it can beclosed off, and the remainder of the system could remain in service. Accessibility dur- ing a fire should be considered when locating fire 5.6 UtilitySystems.This section dealswithpneu- hose stations and/or turrets. In the determination matic,firewater, potable water,sewageandrelated of required flow rates, consideration should be systems. givento the surface area, location of the equip- a. Pneumatic Systems. Pneumatic systems are ment and to the maximum number of discharge required to provide a dependable supply for pneu- nozzles which could be in use simultaneously (See maticallyoperated components. All pipe, tubing NFPA, National Fire Code, Volumes 6 and 8; API andfittings 3/8 inch nominal size andsmaller RP 14G). should be AIS1 316 or 316L stainless steel, with c. PotableWaterSystems.Threadedand coupled 0.036 inch minimum wall thickness where exposed galvanized steel pipe, and bronze valves should to the atmosphere. Synthetic tubing may be used generally be used in potable water service. Cop- in weatherproofenclosures or in fire loop safety per pipe maybeusedyithinthe confines of systems(SeeSection 2.1.e). Fire loop safety sys- buildings. joint Toxic compounds shouldbe tems should be in. accordance with API RP 14C. avoided. If water makers are used,considera- Piping should beeinstalled In a manner that wlll tion should be given to potential contamination minimize low polnts or traps for liquid.Outlets of the water from heating sources.When po- from vessels and piping should be from the top of table water is supplied to other facilities such the system and drains from the bottom. Blowdown as engine water jacket makeup, etc., care provisions should be included in the pipingsystem should exercised be topreventcontamination to allow removal of condensation. Pneumatic sys- from backflow. tems should be tested in accordance with Section 7.4.c. d. Sewage Systems. Interior sewage piping, such as ln llvlng quarters areas, shouldbecarbonsteel, (1) A i r Systems. Main air headers should utilize cast iron pipe with babbit, or lead sealed joints or corrosion resistant material such as threaded non-metallicpipeproperlysupported perANSI and coupled galvanized steel. Piping drops to B31.3. Exterior piping may be carbon steel, cast instruments should be in accordance with iron, or non-metallic (when roperly supported Paragraph 6.6.a. Care must -be exercised in and protected from sunlight), 111 piping should be locating air compressorsuctions topreclude well supportedandhave a minimum slope of /S the introduction of gas or hydrocarbon vapors inch per foot. The system should be designed with into the system. No cross-overs, whereby air adequate clean-out provisions. Discharge lines and gas could be intermixed, should be allowed fromsewagetreatmentplants shoyld terminate anywhere in thesystem. nearwater level and containreadilyaccessible sampling connections. Care should be exercised in (2) GasSystems. For gas systems,ventsand locating vents. reliefvalvesshould bepiped to a safe 5.7 Heating Fluid and Glycol Systems. The para- location if it is determined that the volumes mountsafety consideration inthe design of heating capable of being vented could create an fluid systems is containment of the fluid for personnel abnormal condition. The gas source chosen protection and fire prevention.Allpiping,valves and shouldbe thedriest gas availableonthe fittings should be in accordance with Sections 2, 3, and platform. The following guidelines may be 4 except that flanges for other than pressure steam low helpful in designing an instrument gas (or and hot water systems should be a minimum of ANSI a fuel gas) system: 300 lb to minimize leakage. Piping should be designed (a) Consideration should given be tothe for thermal expansion (See Section 2.8). Thermal insu- necessity of dehydrating the gas prior lation should be in accordance with Section 6.6. totaking a significantpressuredrop. a. If the process side of a shell tube and heat An external source be heat may re- exchangerhas a higheroperatingressurethan quired to prevent freezing if the gas is the design pressure of the heating Euid side, the not dehydrated. heating fluid side must be protected by a relief (b) The gas should expanded be into a device. The location of the rellef device depends on separatortopreventhydratesandli- the actual design of the system. If possible, the quids from entering the system piping. reliefdeviceshould be located on the expansion (surge) tank which will serve as a separator. All (c) The inlet and outlet pressure rating of heating fluid should pass through expansion pressurereduction devices should be (surge) tank to allow venting of any gaspresent. A carefully considered. If the outlet pres- relief device may also berequired attheheat sure rating is less than the inlet source exchanger. Consideration should also be given to tube failure in heat exchangers where the operat- pressure, a relief device should be close- ing pressure of the heating fluid system exceeds coupled to the reduction device. the test pressure of the process system. (d) Parallel reduction devices should be b. The effect of mixing hot fluids with cold considered tomaintainsystemopera- fluids (see A P I R P 621, Section37)shouldbe tionin the eventtheprimary device considered whendetermining how t o dispose fails. of thedischarge of a relief deviceon a heatCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 40. RP 14E: Offshore Production Platform Piping Systems 39I COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 41. A P I RP*KL4E 91 0732290 0099522 2 W 40 Petroleum American Institute exchanger,separate A scrubbermay be re- relief header must be shut down. Alterna- quired. tively, a full opening block o r check valve c. Heatingsystems(excepthotwater or steam) may be installed downstream of relief de- should preferably be pneumatically testedin vices if connecting to a common relief accordance with Section 8.4.c. If hydrostatically header, All block valvesinstalled either tested,provisionsshóuld be made for removal upstream or downstream of reliefdevices of all water from the system before placing in should equipped locking be with devices service, Additionally, any water remaining after andoperated in accordance ASME with drainingshould be removed a t startup, by Section VIII, Appendix M. slowly bringing the system to 212°F and vent- (3) Piping on the exhaust side of relief devices ing the generated steam. Care should be taken shouldbedesigned to minimize stress on to ensure that each branch of the system has the device. Thepipingshouldalso bede- circulation during this period, signed withstand maximum to the back d. The exhaust stream from a glycol reboiler con- pressure to which i t could besubjected. tainssteamandhydrocarbonvapors.Caution Theallowableworkingpressure of relief should exercised be in thedesign of reboiler valvesis covered by API Spec 526. exhaust piping to prevent back pressure, igni- c. Relief (Disposal) System Piping. The relief Sys- tion, and condensation problems, tem and piping should be designed to dispose of the relieved product in a safe and reliable manner. 5.8 Pressure Relief and Disposal Systems. The system and piping should be designed to pre- vent liquid accumulation so that the design reliev- a. General. Pressure relief disposal and systems ing capacity of any of the pressure relieving de- are required to prevent over pressure of process vices IS not reduced. Additionally, the design components and to dispose of the relieved prod- should limit back pressure. The ma;ximumpossi- uct in a safe manner. Some possible causes of blebackpressure a t each relief pointshouldbe over pressure downstream are blockage,up- determined. This is particularly important where stream control valve malfunction, and external two or more relief devices may relieve simultane- fire. ously into the same disposal system. The materials, fittings, welding and other design criteria should (1) The commonly used safety relief devices conform to the respective parts of this RP and arethe conventional spring loaded relief API RP 520, Part II. valve, the balancedbellows spring loaded relief valve, the pilot operated relief valve, (1) Vent or flare structures should be designed thepressure-vacuumreliefvalve,andthe t o preventbucklingcausedby windmo- rupture disc., For acompletedescription, ment. Vent or flare structures should pre- operation,sizing, pressure setting, and ferably be installed on the down wind side application guide, see ASME Section VIII, of theplatform,takingintoaccountheli- API RP 520 Part I, API RP 521 and API copter and boat approaches, etc. In deter- RP 14C. mining and heightdistance the from (2) devices Relief in gas o r vapor service platform, consideration should be given to should normally be connected t o either the accidental ignition due to lightning, falling vessel vaporspace or the outlet piping. burning fluid, and heatradiation. Theyshouldbelocatedupstream of wire mesh mist extractors. Liquid relief devices (2) Whenhydrocarbonvaporsaredischarged should be locatedbelow the normal liquid intotheatmosphere,mixtureswithinthe level. flammable range will occur downstream of the outlet. To determine the location of this (3) If vessels with the same operating pressure flammable mixture, and theintensity of are in series, a relief device set a t the low- the heat should the mixture become ignited, est design pressure in the system may be refertoAPIRP 521 andAPI Proceed- installed on the first vessel, If any remain- ings, Vol 43 (III) (1963),Pages 418433. ing vesselcan be isolated,arelief device When toxic vapors are discharged into the sized for fire or thermalexpansionisre- atmosphere, systems should be designed in quired. Relief devices should be located so accordance with EPA AP-26, Workbook of they cannotbe isolated from any part the of Atmospheric Dispersion Estimates. system being ptotected. (3) If feasible, all relief systems should be de- b. ReliefDevicePiping.* signed for a minimum pressure of50 psig in order to contain flashback.In most cases, (1) If a spring loadedrelief valveisused, it vents from atmospheric pressure equipment mayhave a fullopening block or check should equipped flame be with arrestors valve upstream plus an external test port for flashbackprotection,Flamearrestors for testing and calibrating. If not, it will are subject to plugging with ice and should be necessary to remove the valve for test- not used be in cold climates.Flamear- ing. If a pilot operated relief valve is used, restors should be inspectedperiodically theupstreamvalvingisnotrequiredfor for paraffinbuild-up. testing purposes. (2) Should the relief device have to be removed, 5.9 Drain Systems. Drain systems should de- be process systemsconnectedto a common signed to collect and dispose of contaminants from all sources.A good drainsystempreventscontaminants *This sectionappliestosystemscoveredbyASME from spilling overboard; prevents the accumulation of Section VZZZ, Division 1. Refer to ASME Boiler and flammable liquids on the deck or pans; and promotes Presswe Vessel Code Section Z f o r heating boilers. V good housekeeping practices.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 42. A P I R P * 1 4 E 91 W 0732290 0099523 4 M RP 1 4 E Offshore Production Platform Piping Systems 41 a. Pressure Drains. When pressure (closed) drains that platform movement must aIso be considered. Once frompressure vessels are used, should they be the maximum platform movement has been deter- piped directly to the disposal facilities, independ- mined, designshould be inaccordance withSection 2.8. ent of the gravity drains, to prevent the introduc- tion of fluids from the pressure drains into the 6.11 Risers. Risers should be designed for maximum gravity drains. The design pressure of the inter- wave loading, internalpressure,marinetraffic,and connecting piping and drain valve on each process otherenvironmental conditions. Ifbottom scouring component shouldequal or exceed the highest action is anticipated, the lower end of risers should be pressure to which the system could be subjected jetted below the mudline, when feasible, to avoid undue and correspond to the highest working pressure stresses. Risers on the exterior of that sideof the jacket process component in the system. Piping shouldbe normally accessed byboats,should be protectedby in accordance with Sections 2, 3, and 4. A separate bumpers. See Section 6.5.a. (3) for corrosion protection closed drain system should be provided for hydro- in thesplash zone. gen sulfide service to permit safe disposal of the fluids. 6.12 Sampling Valves. Valves for sampling process b. Gravity Drains. Platform decks and skid pans are streams should be provided at appropriate locations. usually drained by gravity to the disposal facili- Valves should be locatedso that representative samples ties. A wide variety of materials may be satisfac- will be obtained. Sample valves may be used in con- tory for this service. If steel pipe not satisfactory junctionwith samplecatchers or withsampletubes forhydrocarbonservice is used, it should be which extend into the center of the pipe. Consideration marked in accordance with Section 2.1.d.Consid- should be given tothequalityand condition of the eration should be giventominimizebendsand stream at each location. Valve design and piping should flow restrictions in the system. The gravity drain allow cleaning or rodding of valves which may become system should be equipped with one or more vapor pluggedwith solids. Valves subject to large pressure traps or othermeanstopreventgasmigration dropsmaybequicklycut out. Double valvingand from the collection vessel to the open drains. Pip- proper sampling procedures can minimize such prob- ing should be installed with a downward slope on lems. Sample valves are usually ‘/z inch austenitic stain- the order of 56 inch per foot. In some cases, it may less steels (SeeSection 3.5.a). be necessary to install runs in a horizontal plane, but in no circumstances should upslopes be per- 6.13 References. mitted. Clean-out connections should be provided. Loudon, D. E., “Requirements for Safe Discharge 6.10 Bridge Piping Between P!atforms. Design of of HydrocarbonstoAtmosphere” API Proceedings, bridge piping is similar to other piping design except Vol. 43 (III) (1963), Pages 418-4$3.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 43. A P I RP*KL4E 7 1 m 0732270 0077524 b m 42 Institute Petroleum American SECTION 6 CONSIDERATIONS OF RELATEDITEMS 6.1 General. This section contains miscellaneous con- Tapes and extruded coatings should gen- siderations relatedto piping systems. erally not be used on platform piping. Experience has shown that severe corrosion 6.2 Layout.The followi?g itemsshould be consjd- canoccurbeneaththeseprotectivemate- ered when planning piplng layout on production rials without any visible evidence. Because platforms: of the difficulty in sandblasting plat- on a. Safety of personnel. forms, it isdesirabletosandblast,prime, b. Compatibilitywithvessel,equipment,andskid - and/or paint pipe and accessories onshore. arrangement (See API RP 2G). c. Acce&ibility t b equipment. (3) Risers.Risersshould be protectedinthe d. Use of natural supports. splash zone. e. Necessity of suitable walkways. b. Corrosion Protectionfor Internal Surfaces. The 6.3 Elevations, Piping elevation on platforms should best method to alleviate internal metal loss be determined by such things as fluidhandled, temper- depends on the type and severity of the corrosion. ature, purpose and personnel access. Piping should not Each case should be considered individually. be installed on grating or flooring; it should have ade- NACE Standard RP-01-76 provides guidelines on quateclearance for maintenance. Overhead piping detecting and controlling piping internal corrosion. should be arranged to provide sufficient personnel head (1)Process Piping. Protective type coatings are clearance. not generally recommended for process piping 6.4 Piping Supports.Platform piping should be internals. Potential solutions include: supported on racks, stanchions or individual standoffs. (a) Dehydration of process streams. The location and design of supports are dependentupon (b) Use of corrosion inhibitors. routing, media, weight, diameter, shockloads, vibratipn, ( c ) Sizing of pipe for optimum velocity. etc. Consideration should also be given to seal welding (d) Use of corrosion resistant metals. to minimize corrosion; providing sufficient clearance to permit painting; installing and doublers (additional (2) Water Piping. Potential solutions to mini- metal) under clamps and saddles. Valve su ports should mize internal corrosion of water service not interfere with removal of the valve For repair or piping include: replacement. See Sections 2.8 and 5.3.e of this RP and (a) Oxygen removal and/or exclusion. ANSI B31.3 for a discussion of piping flexibility and (b)Chemical treatment(corrosioninhibi- support requirements. tion, biocides, scale and pH control). 6.6 Other Corrosion Considerations. (c> Protective coating and linings (plastics . . and cement). a. Protective Coatings for E x t e r n a l S u r f a c e s . (d) Non-metallic piping. Design, selection and inspectionof an external pip- (e) Control of solids (sand, mud, sludge). ing systemshquldbebased on NACE Standard (3) Protective Coatings. If internal coatings are RP-01-76,Sections 10, 12, 13 and 14. Additional used, the piping should be designed to facill- points to consider with external coatings a r ë pro- tate fabrication without damage to the vided below. coatings. (1) Types of Platform Piping Coating Systems. c. Compatibility of Materials. different When All steel piping should be protected with a metals are coupled together in the presence of coating (painting) system which has been an electrolyte,galvanicaction will occur.The proven acceptable in a marine environment greater the differenceelectromotive in force by prior performance or by suitable tests. (emf) .of the metals in the galvanic series, %he (2) Selection of Platform Piping Coating SYS- moreseverethecorrosion,Thepossibility of tems. When selecting coating systems, the galvanic corrosion should be taken into account following points should be considered: when selecting the materialsof construction for piping, valves and fittings. Some general guide- (a) Surface preparation. lines follow: (b)Temperatureranges (maximum-mini- mum) expected. (1) Whenever possible,use thesame metal ( c ) Dry and/or wet surfaces. throughout, or metals close together on the (d) Chemical contamination expected. galvanic series. The carbon steel materials (e) Location of equipment under considera- recommendedinSections 2, 3, and 4 are tion(heightabovesplash zone, maxi- compatible. mum wave height, etc.). (2) Thefollowingalternativesshould becon- (f) Abrasion expected. sidered if it is necessary to utilize differing (g) Application of coating system. metals: (h) Maintenance. (a) break the couple with unions, nipples, bushings or sleeves made of a non- Afterth0 above requirementshave been conducting material. determined, they shouldbe submitted t o the (b) exclude the electrolyte by the applica- operator’s Corrosion Engineer, a reputable tion of a protective coating to one or paintmanufacturer’srepresentative, or a both metals. consultingengineering firm for specific (c) keepthelessnobleoranodicmember recommendations, specifications,in- and largecomparison the in with more spection services. noblemetal.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 44. A P I RP*KL4E 91 m 0732290 0099525 8 m RP 14E: Offshore Production Platform Piping Systems 43 d. Non-Destructive Erosion and/or Corrosion Sur- b. Tables 6.1 to 6.3 provide typical minimum insula- veys. Access should be provided to points in the tion thicknesses for various conditionsof tempera- pipingsystemwhereerosion and/or corrosion ture and service. is anticipated. These points should be examined] a s soon as practicalafterstart-up,byradio- 6 7 Noise. In the design of platform piping systems, . graphic or ultrasonic methods and documented provisionsshouldbe made to protect personnelfrom forcomparhon future with surveys. Special harmful noise. Problems and solutions are discussed in emphasis should givenwell be to flowlines] depth in APT Medical Research Report EA 7301, bends and production manifolds. Guidelines on Nozse. A general discussion of noise e. CathodicProtection.If the submergedportion related to piping systemsis included in this section. . of a pipeline i s to be cathodically protected by a. Noisë in a piping configuration is caused by the a system other than that used toprotectthe turbulence of a fluid passing through the system. platform] its riser should be isolated from the Turbulence is created downstream of restricted platform. This may beaccomplished with an in- openings and increases as the fluid velocity in- sulating flange above the water and insulating creases. Most noises in piping systems may be material insertswithin the stand-off clamps attributed to the various types control valves. of below the insulating flange. The sound pressure level may be calculated for control valves from formulas and data supplied 6.6 Thermal Insulation. Thermal insulation should by the various manufacturers, beused on platformpipingforpersonnel protection, b. Thefundamentalapproachtonoisecontrolin prevention of combustïon from hot surfaces, heat con- piping systems should be to avoid or minimize servation, freeze protection and prevention of moisture the generation of harmful noise levels. Methods or ice on piping. For personnel protection, all readily thatmay be effectiveinavoidingsuchlevels accessible surfacesoperating above 160°F shouldbe in piping systems include: insulated. Surfaceswïthatemperaturein excess of (1) Minimizefluidvelocities. Thenoiselevels 400°Fshould be protected from liquid hydrocarbon generated the by recommended velocities spillage, and surfaces in excess of 900°F should be pro- in Section 2 should be acceptable. tected from combustiblegases, (2) Select controlvalves of a type or with a. Guidelines for proper insulation include: special trim to minimize noise. (1) Piping shouldproperly be cleanedand c. Methods thatmay be effective inminimizing primed prior to insulating. noises in piping systems include: (2) Insulating material shouldbeselected for (1) Avoid abrupt changes in flow direction, the particular temperatureconditions. Insu- (2) Use venturi (conical) type reducers to avoid latingmaterial, as such magnesia] that abrupt changes in flow pattern. could deteriorate or cause corrosion of the (3) Use flow straightening vanes reduce to insulated surface if wet, should not be used. large scale turbulence. Some commonly used insulating materials (4) Use extra heavy wall pipe and fittings to are calcium silicate, mineral slagwool, glass attenuate sound and vibration API (See fiber and cellular glass. Medical Research Report EA 7301). (3) A vapor barrier shouldbeapplied to the (5) Use acoustic insulation and/orshielding outersurface of the insulationon cold or around pipe and fittings to absorb isolate PlPlng. sound. (4) Insulation should protected sheet be by ( 6 ) Use flow stream silencers for extreme cases. metal jacketing from weather, oil spillage, 6.8 Pipe, Valves and Fittings Tables. Detailed mechanical wear]or other damage. If alumi- information concerning pipe, valves and fittings may be num sheet metalis used for this purpose, it readily shownusingtables.Information that may be should be protected by an internal moisture shown in the tables includes size ranges, generalspeci- barrier. fications, valve figure numbers, pressure ratings, (5) To prevent HzS from concentrating around temperature Iimitations, pipe schedules, material speci- thebolts,flangesshouldnotbeinsulated fications, special notes, etc. Such tables are generally in H& service. prepared by an operator for use as a general company- (6) Certainheatingfluidsarenotcompatible wide guide. Examples of Pipe, Valves andFittings with someinsulatingmaterialsandauto- Tables are provided in Appendix C. ignitionmay occur. Caution be should 6.9 Inspection, Maintenance, Repairs and Altera- exercised in selecting materials. tions are importantconsiderations after a platform pip- (7) Certain insulation materials may be flam- ing system has been commissioned. API 510, which is mable. writtenforPressure Vessels,containsguidelines on (8) Preformed insulation jacketing and are these which topics can alsoapplied be to piping available for various size pipe and fittings. systems.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 45. API RP*LL)E 91 m 0732290 009952b T m 44 American Petroleum Institute TABLE 6.1 TYPICAL HOT INSULATIONTHICKNESS(INCHES) n 1 2 3 4 6 6 8 9 Maximum Size, Pipe Nominal Inches Temperature r ("F) 1%& Smaller 2 36 4 8 10 12 & Larger 250 1 1 1 1% 1% 1% 1% 1% 500 1 1% 1% 1% 2 2 2 2 600 1% 1% 2 2 2 2% 2% 2% 2 750 3 3 TABLE 6.2 TYPICAL COLD INSULATIONTHICKNESS(INCHES) 1 2 35 4 6 79 8 10 1 12 13 1 14 15 16 17 18 19 20 Nominal Minimum Pipe Size, Inches Temperature . ("F) Flat % 1 6 41% 2 32% 8 14 10 16 12 18 24 20 30 Surf. 40 1 1 1 1 11 11 1 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 30 1 1 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 20 2 2 12 ~2 1 2 ~ 2 2 1 2~ 21 2 ~ 2 1 ~ 1 ~ 1 ~ 1 ~ 10 1% 2%2%2 2 21%2 2 2%2%1% 2 2% 1% 2% 2% 2% 2% 2% 2% 2%2 2 2 1% 2 2% 2% O 2% 2% 2% 2% 2 2 33 3 -10 2 2 2 2 2 2%2%2%2% 3 3 3 3 3 3 3 3 3 3% -20 2 2 2% 2 2% 2% 2% 2% 3 3 3 3 3 3% 3% 3% 3% 3% 4 TABLE 6.3 TYPICAL INSULATION FOR PERSONNEL PROTECTION (Applicable Hot Surface Temperature Range (OF)) 6 1 2 5 3 4 7 8 Nominal Pipe Nominal Insulation Thickness (Inches) Size (Inches) 1 2% 1% 2 3 3% 4 1041-1200 731-1040 164-730 "" "" "" % 641-940 941-1200 160-640 "" "" "" "" 1 711-960 160-710 961-1200 "" "" "" "" 1% 160-660 661-880 881-1200 "" "" "" 160-640 2 641-870 871-1090 lOfiIiZ00 "" "" "" 160-600 i% 4 1161-1200961-1160 621-960 160420 160-600 601-810 811-1000 1001-1200 601-790 971-1125 791-970 "" 11261i200 "" "" "" "" "" ""741-930 551-740 160-550 6 931-1090 1091-1200 "" "" 8 "" 1091-1200 901-1090 741-900 160-740 "" "" 10 1061-1200 751-900 901-1060 160-750 "" "" 12 1031-1170 901-1030 741-900 "" ~~~~160-740 1 7 -i O 1 1iO "" 14 1131-1200 1001-1130 861-1000 ""701-850 160-700 "" 16 1121-1200 841-980 160-690 981-1120 691-840 "" "" 18 1101-1200 831-970 160-690 971-1100 691-830 "" "" 20 831-970691-830 "" 160-690 971-1100 1101-1200 "" 24 1091-1200 160-680 961-1090 821-960 "681-820 " "" 30 1081-1200 681-810 951-1080 160-680 811-960 "" Flat Surface* 901-1010 791-900 1011-1120 661-790 521-660 160-520 112i-1200 *Application range also applies to piping and equipment over30 inches in diameter. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 46. API R P * 1 4 E 91 m 0732290 0099527 L m RP 14E: Offshore Production Platform Piping Sysfems 45 SECTION 7 INSTALLATION AND QUALITYCONTROL 7.1 General. This section covers fabrication, assem- f. Heat Treatment. ANSI B31.3 covers heat treat- bly, erection, inspection, testing and related operations ment, including pre-heat and stress relieving. associated with the installation and quality control of metallic non-metallic and platform piping systems. g. Examination and Inspection. Visual, radiograph- Fabrication, assembly, erection, inspection, testing and ic andultrasonic examination and inspection relatedoperationsshouldcomplywithANSI B31.3, should comply with ANSI B31.3. Additional except as modified herein. recommendations are provided below. 7.2 Authorized Inspector. A minimum of 5 years (1) Radiographic Inspection. It is recommended experience in design, fabricationor inspection of indus- that platformpiping in hydrocarbonservice trial pressure piping should be required to qualify as regardless of servicetemperatureand pres- an authorized inspector. sure be radiographically examined in accord- ance with Table7.1. 7.3 Welding. a. Safety Precautions. Prior to and during burning TABLE 7.1 and welding in any area on a platform which con- MINIMUMEXTENT O F RADIOGRAPHIC tains hydrocarbon process equipment, thorough WELD EXAMINATION checks should be made visually, and with a porta- FOR CARBON STEEL MATERIAL ble combustible gas detector, to determine that the area is free of flammable liquids and combustible PercentClass Pressure of Welds gas mixtures. The supervisor on the platform shouldhaveknowledge of all simultaneous 160 lb to 600 lb ANSI __ 10% activities. and lb 900 1500 lb ANSI 20% (1) An inspection should be made prior to the 2500 lb ANSI, 5000 lb and API, Higher 100% commencement of any burning or welding to ensure the welding machines are equipped with spark arrestors and drip pans; welding 7 4 Pressure Testing. Prior to being placed in oper- . leads are completely insulated and in good ation, piping should be pressure tested for leaks. Prep- condition; oxygen and acetylene bottles are aration for testing, hydrostatic and pneumatic testing securedproperly;andthehosesareleak are covered by ANSI B31.3 except as modified below. freeand equipped. with proper fittings, gages, and regulators, a. Hydrostatic Tests. Water should be used in all (2) Duringweldingorburningoperationsin hydrostatic testing unless would have an adverse it an areawhich contains hydrocarbon process effect on the piping or operating fluid. Any flam- equipment, one or more persons, a s neces- mable liquids used for testing should have a flash sary,should be designated for firewatch. point above 150F. Personsassigned watch to fire should (1) When a system is tobe tested, the following have no other duties while actual burning equipment should be isolated: or welding operations are in progress. They shouldhaveoperablefirefightingequip- (a)Pumps,turbinesandcompressors. ment in their possession and be instructed (b) Rupture discs and relief valves. in its use.No welding or burning (except (c) Rotometers and displacement meters. hot taps) shouldbepermittedonlinesor (2) Thefollowingequipmentshouldbetested vesselsuntiltheyhave been isolatedand t o design pressure and then isolated: rendered free of combustible hydrocarbons. (a)Indicatingpressure gages,when the (3) Adequate lighting should be provided on a test pressure will exceed thescale platform when welding or burning at night. range. (b) External float type level shutdown de- b. Welding Procedure Qualification. Tests should vices controllers, and when float the be conducted to qualify welding procedures to be is not rated for the test pressure. The utilized. Procedure qualification methods and re- float should be subjecteddesign to quirements are detailed in ANSI B31.3. pressure; then the float chamber should c. Welder Qualification. Welders shouldbequali- be isolated from the system. fied using the specific qualified welding procedure (3) Check valves should be held-open and block for the proposed job. ANSI B31,3 contains details and bleed ball valves should be in the one forqualifyingwelders, including variables the halfopenposition during testing. that make requalification necessary. b. Pneumatic Tests. Pneumatic tests should be per- d. WeldingRecords.Testrecords of thewelding formed accordance in with ANSI B31.3 when procedure qualification and the welder perform- hydrostatic tests would be undesirable, such as in ancequalificationshouldbe maintained per instrumentair,heatingfluid,andrefrigeration ANSI B31.3. systems.Inasmuchaspneumatictestingmay create an unsafe condition,special precautions e. Welding Requirements. ANSI B31.3 covers should be taken, and carefulsupervision should be welding requirements and in addition welding provided during testing. Only air or nitrogen (with should not be done if there is danger that the qual- or withouttracers) shouldbeused asthetest ity of the weld may be affected by atmospherlc medium. Each test system shouldbe kept as small conditions. as practical.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 47. A P I RP*I4E 91 m 0732290 0099528 3 m 46 Institute Petroleum American The test pressure shouldbe 1.1 times the of approximately 16 psi until the final test maximum designpressure, or 100 psig, pressureisreached.Thepressureshould whicheveris the lesser. To guard against then bereduced to 90% of test pressure, brittle fracture hazards, theminimum metal and held for a sufficient length of time to temperature for all components during the permit inspection of all joints, welds, and test should be 60F. connections with soap solution. Pressure should be gradually increased to not more than 26 psig, and held until all 7.5 Test Record. Test records includingwelding jointshave been inspected for leakswith procedure qualifications, welder performance qualifica- soapsolution,Ifnoleaks are found, the tions and pressure testing should be in accordance with pressure should be increased in increments ANSI B31.3.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 48. A P I R P * 1 4 E 71 0732270 0077527 5 RP 14E:Piping Systems Production Offshore Platform 47 APPENDIX A EXAMPLEPROBLEMS Introduction. appendix This demonstrates, means by of solutions toexampleproblems, applications of the piping design guidelines presented in this RP. EXAMPLE A l FLOWLINEPIPINGDESIGN Al.1 Problem Statement. Design a flowline for a where: gas-condensate completion. P = operating pressure, psia. Al.l.l The completion is expected to have the fol- SI =liquid specific gravity (water = 1 ; !se lowing initial characteristics: average gravity for hydrocarbon-water m1x- a. Shut-in wellhead pressure= 6600 psig. tures) at standardconditions. b. Maximum test and productionflow rate expected R = gasfliquidratio, CU ft/barrelatstandard (including surge) : conditlons. T = operating temperature, "R. Qg = 16 million cubic feet/day S = gas specificgravity (air = 1) at standard , [S, = .66 (air = l] ). conditions. QI = 60 barrels condensate/million cubic Z = gas compressibility factor, dimensionless. feet gas [SI = .80 (water = l ) ] . c. Flowing tubing pressure = 4500 psig. For Initial Conditions : d. Flowing temperature = 120°F. S = .80 1 P = 4600 psig + 14,7 = 4616 psia A1.1.2 The completion is expected to have the fol- lowing characteristicsat depletion: R = lJoooooo ft = 20,000 CU ft/barrel 60 barrels a. Flowing tubing pressure = 1600 psig. Sn = .66 Qg = 10 million cubic feet/day T = 120°F + 460 = 680"R [S, = .65 (air = l ) ] . QI = 20 barrels condensate/million feet cubic z = 0.91 gas [SI = .80 (water = l)], and 1600 bar- rels of produced water per day [SI = 1.08 Inserting ia Equation 2.9: (water = l)]. Pm = + 12409 x .80 x 4616 2.7 x 20,000 x .66 x 4616 A1.1.3 Equivalent length of flowline = 60 feet. + 198.7 X 4616 . 20,000 X 580 x 0.91 . = 17.8 lbs/fb(initial) A1.1.4 Flowline to be designed for wellhead pres- sure. For FinalConditions : A1.2 Solution. S1 lOmmcf / d X 20 bbl/mmcf = + x .80 1600 bbl/day x 1.08 10mmcf/d~20bbl/mmcf+1600bbl/day A1.2.1 General. The following items should be con- = 1.04 sidered: a. Erosional velocity. P = 1600 psig + 14.7 = 1615 psia 10 mmcf /d b. Pressure containment. c. Noise. R = = 10 mmcf/d x 20 bbl/mmcf 5880 CU ft/barrel + 1500 bbl/day d. Pressure drop. Sg = .66 A1.2.2 Erosional Velocity. Since the well will flow T = + 120°F 460 = 680 "R continuously and little or no sand productionis antici- 55 = 0.81 pated, Equation 2.8 with a n empirical constant of 100 Inserting in Equation 2.9: will be used to calculate the maximum allowable ero- sional velocity (See Section 2.6.a). 12409 x 1.04 x 1616+2.7 x 6880 x .66 x 1616 pm = C 198.7 x 1616 + 6880 x 680 x 0.81 Ve =- Eq. 2.8 = 11.6 Ibs/ft3 (final) v L where: A1.2.2.2 UsingtheabovevaluesinEquation 2.8 Ve = fluid erosional velocity, feetlsecond. gives : c = empirical constant; 100 Ve (initial) = - = 23.7 ft/sec = 100 for continuous service with minimum v 17.8 solids. 100 = gaspiquid density at operating pressure Ve (final) = - = 29.5 ft/sec pm and temperature, Ibs/ft3. v 11.6 A1.2.2.1 prn will be calculated for initial and final A. Using Equation 2-10, the minimum allow- flowing conditions, to determine which conditions con- able cross-sectional areas can be determined trol, using Equation2.9. RTZ 9*35+ 21.2sp Pm = 12409 S P 1 + 2.7 R S g P Eq. 2.9 A = V, Eq. 2.10 198.7P + RTBCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 49. A P I RP*L4E 9L 0732290 0099530 L 48 American Petroleum Institute where : Actual yield strength - 6600 psig A = minimum pipe cross-sectional area required, 36,000 psi - 6307 psig m2/1000 barrels liquid per day = Actual yield strength 36,272 psi For InitialConditions : c. Check availability of 4 inch nominal XXS Grade A = 936 " 20,000 x 680 x 0.91 21.26 X 4616 d. X42 pipe which will meet the required6600 psig pressure requirement. Consider using a pressure reliefdeviceon a 4 23.7 inch nominal XXS line until the wellhead shut-in = 5.04 in2/1000 bbl/day pressure declines to 5307 psig. A = 5.04 in2/1000 bbl/day X (15 mmcf/d X 50 bbl/mmcf) e. Recheck the finalwellconditionsprediction to = 3.78 in2 (initial) determine if slightlylower flows mightexist which would allow a 3 inch nominal XXS line ta For Final Conditions: suffice for the life of the well. The amount of A = 936 " 6880 x 580 x 0.81 2126 x = 3.23 in2/1000 bbl/day f. surge included in the maximum flow rate should be examined in detail to seeif it is reasonable. Consider installing a 3 inchnominalXXSline 29.5 initially, then replacing it with a larger (inside A = 3.23 in2/1000 bbls/day x (1600 bbl/day + 10 mmcf/d diameter) line later in the life. X 20 bbl/mmcf/d) = 5.49 in2 (final) A1.2.4 Noise. The yelocity (and relative indication A1.2.2.4 Although the allowable erosional velocity of the noise) in the llne will be determined for initial is higher for thefinal conditions, the linesize will still andfinal conditions todetermine which conditions be controlled by the final conditions since the liquid control. volume is higher. A1.2.4.1 The velocity can be determined as follows: A1.2.2.5 Awill be convertedintoaninsidepipe diameter as follows: For Initial Conditions : weight flow of gas A =-T di2 - 16 mmcf/d X .65 X 29 lbs/lb mol air 4 - 86,400 sec/day X 379 CU f t / l b mol = 8.64 lbs/sec di(initial) = I I 4 x 7r 3*78 = 2.19 inches inside diameter. weight flow of condensate .-"0"- ~~~ x 649 = 2.64 inches inside - 16 mmcf/d x 50 bbls/mmcf X .80 X 350 lbs/bbl water dl(final) = II4 86,400 sec/day T diameter. A1.2.3 Pressure Containment. A preliminary line size can now be selected using Table 2.5. The required = 2.43 lbs/sec Total weight flow of wellstream (initial) = 11.07 lbs/sec For FinalConditions: 4 pressure rating of the line must be greater than 5600 PSW weight flow of gas A1.2.3.1 The two obvious choices are listed below: - 10 mmcf/d x .66 x 29 lbs/lb mol air - 86,400 sec/day x 379 CU ft/lb mol Grade B Pipe = 5.76 lbs/secax InsideNominal weight flow of condensate SchedulePressure SizeDiameter Line - 10 mmcf/day X 20 bbl/mmcf X .80 X 360 lbs/bbl water 3XXS inch 2.30 inch 6090 psig - 86,400 sec/day 4XXS inch 3.16 inch 5307 psig = .66 lbs/sec The 3 inch nominal pipe has the required pressure weight flow of water rating, but the internal diameter is too small for the - x 360 lbs/bbl - 1500 bbl/day sec/day final conditions. The 4 inch nominal pipe has sufficient 86,400 internaldiameterforthefinalconditions,but the = 6.08 lbs/sec required working pressure is slightly deficient if Grade B pipe is used. Total weight flow of wellstream (final) = 12.48 lbs/ sec A1.2.3.2 The selection final requiresengineering A1. The flowing velocity will be determined judgment. following The *alternatives should be above for erosionalvelocity, the total volume f l o ~ evaluated: would be: a. Recheck pressure the source of the requirements. Often, shut-in nominal wellhead values final flow volume = 12-48 lbslsec = 1.1ft3/sec 11.6 lbs/ft3 somewhat higher than actual requirements are = &2 ft3/sec supplied to piping designers. If the actual shut- initial flow volume = "O7 in pressure was less than 6307 psig, the 4 inch 17.8 lbs/ft3 nominal XXS would be the proper choice. Thus the final conditions control the maximumveloc- b. Check the mill certification for availabIe 4 inch ity. nominal XXS pipe, t o determine the actualyield A1. The flowing velocity will be determined strength. Although the specified minimum yield for 3 and 4 inch nominal XXS line sizes. strength for Grade B pipe is 36,000 psi,most 1.1ft3/sec pipe exceeds the minimum yjeld by 10% or so. Velocity (3") = ~ / x (2.3/12)2 - 4 - 38.2 ft/sec In this case, if the actual. yleld strength were 36,272 psi, the 4 inch nomma1 XXS plpe would be the proper choice. Velocity (4") = n/4 (3.15/12)2 - 20.4 ft/sec x ft3/sec COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 50. A P I R P 8 1 4 E 91 0732290 0099531 3 m RP 14E:Piping Systems Production Offshore Platform 49I A1.2.4.2 SinCe the Velocity iS leSS than 60 ft/SeC W (initial) = 3180 x 15 x -65 + 14.6 X 15 mmcf/d (See Section 2.4) in both cases, noise should not be a x 50 bbl/mmcf x .80 problem and would not influence the line size selec- = 39,765 lbs/hr tion. A1.2.5 Pressure Drop in the line may be determined using Equation2.11. I W (final) = 3180 x 10 x .65 + 14.6 x (10 mmcf/d X 20 bbl/mmcf + 1500 bbl/day) x 1.04 .. = 46,483 lbs/hr A P = 0.000336f W2 E . 2.11 q di5prn where: A1.2.5.2 Usingtheabovevaluesinequation 2.11 gives: AP = pressure drop, psi/lOO feet. A P (initial 3”) = 0.000336 x 0.019 X (3976512 di = pipe inside diameter, inches. (2.3)5 X 17.8 f = Moody friction factor, dimensionless. = 8.9 Dsi/lOO f t pm = gadliquid density at flowing pressure and .O00336 x-0.0196 x (3976512 A P (initial 4”) = temperature, lbs/ft3 (Calculate as shown in (3.15)s X 17.8 Equation 2.9). = 1.9 - .usi/lOO f t W = total liquid plus vapor rate, lbs/hr. A P (final3”) = .O00336 x 0.0200 X (46483P (2.315 X 11.5 A1.2.5.1 W may be determined using Equation 2.12. = 19.6 usi/lOO f t + W = 3180 Qg Sg 14.6 SI QI Eq. 2.12 A P (final4”) = .OOOi36‘x(3.15)s X. 0.0196 (46483Y x where: , . 11.5 - - .- Qg = gas flow rate, millioncubic feet/day (14.1 = 4.0 psi/lÒO f t psia and 60°F). Refer to Figure 2.3 for Moody friction factor (f). Sg = gas specific gravity (air = 1). A1.2.5.3 Since the linei s only 50 feet long, the total QI = liquid flow rate, barrels/day. pressure drop would not be critical in most cases and SI = liquid specific gravity (water = 1). probably would not influence line size selection. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 51. A P I RPaL4E 91 m 0732290 0099532 5 W 50 Institute Petroleum American EXAMPLE A2 PUMPSUCTION I?IPINGDESIGN A2.1 ProblemStatement.Asinglereciprocating A2.2.2.1 The friction factor, f, may be found from pump will be used to transfer crude oil from a pro- Figure 2.3 using Reynolds the number calculated duction separatorto a remoteoiltreatingfacility. from Equation 2.3: Select a suction line size for this pump application. pl dr VI is Data for the pumping system listed below: Re =- Eq. 2.3 P1 A2.1.1 Operating Conditions of Separator: whme : a. Operating pressure = 60 psig. b. Inlet oil volume = 5000 barrels/day. Re = Reynolds number, dimensionless. c. Inlet water volume = zero. pl = liquid density at flowing temperature, lb/ft3. d. Oil gravity = 40" API (SI = .825). dr = pipe inside diameter, feet. e.Oil viscosity = 1.5 centipoise at pumping tem- perature. V1 = liquid flow velocity, ft/sec. f. Level in separatorwill be controlled constant by PI = liquid viscosity, Ib/ft-sec; bypassing pump discharge back to separator. = centipoise divided by 1488 or; g. Vessel outlet nozzle = 8 inch ANSI 150. = (centistokes times specific gravity) A2.1.2 Pump Data: divided by 1488. a. Volumehandled, 150% of oilinlet(toensure For thisproblem: ability to maintain liquidlevel during surges) pl = 62.4 Ibs/ft3 water X ,825 = 51.49 Ib/ft3 = 7500 barrels/day. dr = 7.98 i d 1 2 = 0.665 feet b. Type Pump = Triplex. V = 1.4 ft/sec (Fig.2.1) 1 c. Pump RPM = 200. PI = 1.5 cp/1488 = 0.001 lb/ft-sec d. Suction Connection = 6 inch ANSI 150. e. Discharge Connection = 3 inch ANSI 600. Re = 51.49 X .665 X 1.4 = 47,937 .o01 f. Required NPSH = 4 psia at operating con- dition. Using Re and the steel pipe curve, f may be found g. Discharge Pressure = 500 psig. from Figure 2.3. h. Pump datum located 15 feet below the separator f = 0.023 fluid level. A2.1.3 The suction line is 60 feet long and contains A2.2.2.2 All of the required values for Equation 2.2 one Tee, four 90" elbows, two full open ball valves, are now known: and one 8 inch x 6 inch standard reducer. QI= 7500 barrels/day S = 0.825 1 A2.2 Trial Solution. From Table 2.3, a suction velocity of 2 feeidsecond is selected to determine a dl = 7.98 inches preliminary line size. From Figure 2.1, for 7500 bar- 0.00115 x 0.023 x 75002 X 0.825 rels/day flow rate, a 6 inch Sch. 40 line gives a AP/lOO ft = (7.98)s velocity of 2.4 feet/sec; and an inch sch. 40 line gives 8 = 0.038 psi/lOO feet a velocity of 1.4 feet/sec. From this, an 8 inch line (7.98 inchinsidediameter)isselectedforthe first Ap Total = x 12 = 0,046 psi trial. 100 A2.2.1 Determine line equivalent length using Table A2.2.3 Next determine available NPSH from Equa- 2.2: tion 2.4. = 4 x 9 f t = 36ft Elbowequivalent length Ball valves equivalent length = 2 X 6 f t = 12 f t + NPSHa = hp - hvpa hst - hf - hvh - ha Eq. 2.4 Tee equivalent Run length = 1 X 9 ft = 9 f t where: Reducer equivalent length =1 x 2ft = 2ft hp = absolutepressureheaddue to pressure, Vessel outlet contraction = 1 x 12 f t = 12 f t atmospheric otherwise, surface or on of 8 inch linelength = 50ft liquid going to suction, feet of liquid. Equivalent Line Length= 121 f t hvpa= the absolute vapor pressure of the liquid at suction temperature, feet of liquid. A2.2.2 Next calculate friction line lossesusing hst = statichead,positiveornegative,dueto Equation 2.2: liquid level aboveor below datum line (cen- A P = 0.00116 f Q12 S 1 Eq. 2.2 terline of pump), feet of liquid. di5 hr = friction head, or head loss due to flowing where: friction in the suction piping including en- A P = pressure drop, psi/lOO feet. trance and exit losses, feet of liquid. f = Moody friction factor, dimensionless. hvh = velocity head = v12/2g, feet of liquid. QI = liquid flow rate, barrels/day. ha = acceleration head, feet of liquid. S = liquid specific gravity (water = 1). 1 VI = velocity of liquid in piping, feet/second. dl = pipe inside diameter, inches. g = gravitational constant (usually32.2ftlsecz)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 52. API RP*KLYE 91 M 0732290 0099533 7 RP 14E: Offshore Production Platform Piping Systems 51l A2.2.3.1 Since the oil is in equilibrium with the gas A2.3 Alternate Solutions. ReferringSection to in the separator, the vapor pressure the oil will be of 2.3.b(5), the following alternatives maybe considered 60 psig also. Thus: " as ways t o increase NPSHa. hvpa= hp = (60 147) psis = 209 feet A2.3.1 Shorten Suction Line. Although it might be .433 psi/ft X .825 possible toshortenthelinelengthsomewhat,the hst = 15 feet (given) acceleration head needs to be reduced by leastat (14.4 - 11.2 - -4811 loo% = 80%; l- 14.4 so this alternativewould not be feasible. A2.3.2 Use Larger Suction Pipe toReduce Velocity. If a 10 inch pipe were used rather than a n 8 inch A2.2.3.2 ha may be determined from Equation 2.5. pipe, the velocity would be reduced from 1.4 ft/sec to L V I Rp C .90 ft/sec (Figure2.1). Likewise, a 12 inch pipe would ha = Eq. 2.5 reduce the velocity t o .62 ft/sec. Since neither of the Kg pipesizeswouldreduce the velocity by 8070 (and where: thereby reduce the acceleration head by 80%), this ha = acceleration head, feet liquid. of alternative would not be feasible. A2.3.3 Reduce Pump Speed. A pump speed of 200 L = length of suction line, feet (not equivalent RPM is already very low, so this alternative would length). not be feasible. V = average liquid velocity in suction line, feet/ 1 A2.3.4 Consider a Pump With a Larger Number of second. Plungers. reasonable alternative The pump RP = pump speed, revolutionsiminute. wouldbe touse a quintuplex,ratherthan a triplex,which would reduce the acceleration C = empirical constant for the type pump; of head by 40%. Since a greater percentage reduc- = .O66 for triplex, single or double acting. tion is required, this alternative is not feasible. A2.3.5 Use a Pulsation Dampener. A properly K = a factor representing the reciprocal of the installed pulsation dampener may reduce the length of fraction of the theoretical acceleration head line used in Equation 2.5 to 15 (or less) nominal pipe which must be provided to avoid a noticeable diameters (15 x 8 i d 1 2 in/ft = í O ft.) disturbance in the suction piping; A2.3.5.1 Recalculate the acceleration head. = 2.0 for crudeoil. g = gravitational constant (32.2 ftlsecz). Substituting Known ha = Values Into 50 x 1.4 x 200 x .O66 Equation 2.5 yields: = 2.9 feet A2.3.5.2 By using a pulsation dampener, the avail- able NPSH would be: 2.0 x 32.2 = 14.4 feet NPSHa = 209 - 209 + 15 - .O9 - .O3 - 2.9 = 11.98 feet. is: A2.2.3.3 The available net positive suction head A2.3.5.3 Since the conservative approach was used NPSHa = 209 - 209 + 15 - a09 -03 - 14.4 indetermining line the length recalculate to the = . 8feet 4 acceleration head, the available NPSH should be ade- quate if a pulsation dampener is used. = A2.2.4 NPSH required .433 psi/ft psi x .825 = 11.2 fee A2.3.5.4 If a greater margin of availableNPSH over required NPSH is desired, then oneof the alter- A2.2.5 Conclusion. Thepumpwouldnotoperate natives discussed above could be included in the sys- under these conditions. tem design in addition to the pulsation dampener. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 53. A P I R P * I Y E 91 m 0732290 009953Y 9 E 52 Petroleum American Institute APPENDIX B ACCEPTABLEBUTTWELDEDJOINTDESIGNFORUNEQUALWALLTHICKNESSES SECTION B1 GENERALEXPLANATORYNOTES B1.l Figure B1.l illustrates acceptable preparations B1.4 The transition between ends of unequal thick- for butt welding pipe ends having unequal wall thick- nessmaybeaccomplishedbytaperorwelding as nessesand/ormaterials of unequal specifiedmini- illustratedinFigure B1.1, or by means of a pre- mum yield strength. fabricated transition piece not less than one half pipe - " diameterinlength. B1.2 The wall thickness of the pipes to be joined, B1.5 Sharp notches or grooves at the edge of the beyond the joint design area, should comply with the weld, where it joins a slanted should be design requirements of ANSI B31.3. avoided. B1.3 When the specifiedminimumyield strengths B1.6 For joining pipes of unequal wall thicknesses of the pipes to be joined are unequal, the deposited and eqùal specified minimum yield strengths, the at weld metal should have mechanical properties least principlesgiven hereinapplyexcept is thereno equal to thoseof the pipe having the higher strength, minimum angle limit to the taper. SECTION B2 EXPLANATION OF FIGURE B1.l B2.1 Internal Diameters Unequal. welding, thetransitionmay be made with a a. If the nominal wall thicknesses of the adjoining taper cut on the inside end of the thicker pipe pipe ends do not vary more than 3/32 inch, no (Seesketch (b)) ; or by a combination taper specialtreatmentnecessary is provided full weld to % thewallthickness of thethinner penetration and bond are accomplished in weld- pipeand a taper from point cut that (See ing (See sketch (a) of Figure BU). sketch (a)). b. Where the nominal internal offset is more than B2.2 External Diameters Unequal. 3/32 inch and there is no access to the inside a.Wheretheexternaloffsetdoesnot exceed % of the pipe for welding, the transition should the wall thickness of the thinner pipe, the tran- be made by a taper cut on the inside end of the sitionmay be made by welding sketch (See thicker pipe (See sketch (b)). The taper ang! (e)), provided the angle of rise of the weld sur- should not be steeper than30°,nor less than14 . face does not exceed 30" and both bevel edges are properly fused. c. For stress levelsabove 20 percent or more of the specified minimum yield strength, where the b. Where there is an external offset exceeding % nominal internal offset is more than 3/32 inch the wall thickness of the thinner pipe, that por- but does not exceed l/z the wall thickness of the tion of the offset over % the wall thickness of thinner pipe, and there. is access t o the inside the thinner pipe should be tapered (See sketch of the pipe for welding, the transition may be (f) ). made with a t a p e r d weld (See sketch (c)). The B2.3 Internal External and Diameters Unequal. land on the thicker pipe should be equal to the Where there are both an internal and an extern offset plus the land on abutting pipe. offset, the joint design should be a combination d. Where the nominal internal offset is more than of sketches (a) to (f) (SeeSketch(g)). Par- % the wall thickness of the thinner pipe, and ticular attention should be paid to proper align- thereisaccez t o theinside of thepipefor ment under these conditions.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 54. . A P I R P * 1 4 E 91 m 0732230 0099535 O m RP 14E: Offshore Production Platform Piping Systems 53I FIGURE B1.l ACCEPTABLE BUTT WELDEDJOINTDESIGN FOR UNEQUAL WALL THICKNESSES 3/32" MAX. 30OMAX.- 14O MIN. ( Ir4 1 30° MAX.- 14O MIN. ( I :4 1 3 (f) (g) 3k No min. whenmaterialsjoinedhaveequalyieldstrength. t = Thickness COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 55. A P I R P * l V E 91 0732290 0099536 2 m 64 American Petroleum Institute APPENDIX C EXAMPLE PIPE, VALVES AND FITTINGS TABLES C.1.1 Introduction, Appendix This demonstrates two examples pipe, valves and fittings tables, by I morevalve manufacturers figure beincluded in the tables. and numbers should C.1.2 Example C.1 shows an index forpipe,valves C.2.2 Valve equivalency tables are availablefrom and fittingstable. severalmanufacturers.Using thesetables,with one manufacturer’s figure number as a base, is possible to it determine the different valve manufacturers’ equivalent C.1.3 Example C.2 shows a 160 lb. ANSI pipe, valves figure numbers. By havingequivalent an figure and fittingstable. number, a valve can be quickly located in a manufac- turer’scatalog. Thisprocedureallowsanoperator to C.2.1 The valve manufacturers and valve figure compare manufacturing details and materials of alter- numbers have not been shown in Example C.2. One or nate valves. EXAMPLE C.l EXAMPLE INDEX PIPE, VALVES AND FITTINGS TABLESService Table A Non-Corrosive Hydrocarbons and Glycol 160 lb ANSI B Non-Corrosive Hydrocarbons and Glycol 300 lb ANSI C Non-Corrosive Hydrocarbons and Glycol 400 lb ANSI D Non-Corrosive Hydrocarbons and Glycol 600 lb ANSI E Non-Corrosive Hydrocarbons and Glycol 900 lb ANSI F Non-Corrosive Hydrocarbons and Glycol 1600 lb ANSI G Non-Corrosive Hydrocarbons and Glycol 2600 lb ANSI H Non-Corrosive Hydrocarbons API 2000 psi I Non-Corrosive Hydrocarbons API 3000 psi J Non-Corrosive Hydrocarbons API 6000 psi K Non-Corrosive Hydrocarbons API 10000 psi L Air 160 lb and 300 lb ANSI M Water 126 lb Cast Iron N Condensate Steam and Steam 160 lb, 300 lb, 400 lb and 600 lb ANSI O Sewers and Drains Atmospheric P(Spare) Q (Spare) R (Spare) SV Valves for Corrosive Service General Hydrocarbons Corrosive AA 160 lb ANSI BB Hydrocarbons Corrosive 300 lb ANSI CC (Not Prepared) Corrosive Hydrocarbons 400 lb ANSI DD Hydrocarbons Corrosive 600 lb ANSI EE Hydrocarbons Corrosive 900 lb ANSI FF Hydrocarbons Corrosive 1600 lb ANSI GG Hydrocarbons Corrosive 2600 lb ANSICOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 56. A P I RPSKL4E 91 m 0732290 0099537 4 II RP 14E:Piping Systems Production Offshore Platform 55 EXAMPLE C.2 PIPE, VALVES, AND FITTINGS TABLE TABLE A 150 LBANSI NON-CORROSIVE SERVICE 1 TEMPERATURE RANGE -_ .__-. -20650°F ~ to MAXIMUM PRESSURE ~ DEPENDS ON FLANGE RATING2 AT SERVICE TEMPERATUREnges SizedsGrade Pipe on Service ASTM A106, Grade B, Seamless 3 ?4” andsmaller nipplesthreaded and coupled Schedule 160or XXH 1% ‘’ aiid smaller threaded pipe and coupled Schedule 80 min 2” through 3“ pipe beveled end Schedule 80 min 4”larger and beveled pipe end See Table2.4 Valves (Do not use for temperatures above maximum indicated,) Ball %” and smaller 1500 lb CWP AISI SS screwed, 316 Manufacturers Figure regular port,wrench operated, No. (300°F) Teflon seat %” through 1%” 1500 lb CWP, CS, screwed, Manufacturers Figure regular port, wrench operated, No. Figure or Teflon seat No. (450°F) 2” through 8” 150 lb ANSI CS RF Etc. flanged, regglar port, lever or hand wheel operated, trunnion mounted 10” and larger 150 lb ANSI CS F R Etc. flanged, regular port, gear operated, trunnion mounted Gate % ” and smaller 2000 lb CWP, screwed, bolted Etc. bonnet, AISI 316 SS %I’ through 1%“ 2000 lb CWP, screwed, bolted Etc. bonnet, forged steel 2” through 12” 150 lb ANSI CSR F Etc. flanged, standard trim, handwheel or lever operated Globe 1%” and smaller 2000 lb CWP CSscrewed Etc. (Hydrocarbons) 1% and smaller ” 2000 lb CWP CS socketweld Etc. (Glycol) 2” and larger 150 lb ANSrCS R F Etc. flanged, handwheel operated Check 1%’’and smaller 600 lb ANSIFS screwed, Etc. bolted bonnet4, standard trim 2” and larger 150 lb ANSI CS RF Etc. flanged, bolted bonnet? swing check, standard trim Reciprocating 300 lb ANSL CS R F Etc. Compressor Discharge flanged, piston check, bolted bonnet 4 Lubricated Plug 150 lb ANSICS R F Etc. 1%” through 6” Flanged, Bolted Bonnet (See Section 3.2.c) Non-Lubricated Plug 160 lb ANSICS R F Etc. 1%” through 6” Flanged, Bolted BonnetI (See Section 3.2.c) COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 57. . . A P I R P * l Y E 91 m 0732290 0099538 b m 56 Petroleum American Institute EXAMPLE C.2 (Continued) TEMPERATURE RANGE _______ ~ -20 to 650°F MAXIMUM PRESSURE RATING ON FLANGE 2 AT SERVICE TEMPERATUREtions Rangeseneral Size Compressor Laterals Use ball valves Needle 34” through S’’ 6000 lb CWP, bar stock Etc. screwed, AIS1 316 SS Fittings 5 Ells and Tees M ” and smaller 6000 lb FSASTM screwed A106 1”through i%” 3000 lb FS screwed ASTM A106 2” and Butt larger weld, seamless, wall A234, ASTM WPB Grade to match pipe Unions 3/a “ and smaller 6000 lb FS screwed, A105 ASTM ground joint, steel to steel seat 1”through 1%’’ FSASTM 3000 lb A105 screwed, ground joint, steel to steel seat flanges 2“ and Use larger Couplings smaller 1”and 6000 lb FS screwed A105 ASTM 1%” 3000 lb FS screwed ASTM Aí06 Plugs smaller and 1%” Solid bar forged stock, steel ASTM A105 2” and larger X-Strong seamless, weld cap ASTM A234, WPB Grade Screwed Reducers M” and smaller 160 Sch. seamless ASTM Aí06 1%” 1”through Sch. 80 seamless ASTM A105 Flanges 5 % and 1 ”smaller 150 lb ANSI FS R F screwed ASTM A106 larger 2” and ANSI 150 lb FS RASTM F weld A106 neck, bored to pipe schedule Bolting 2 Class Studs fit, threaded ASTM A193, Grade B I over length 2 Class Nuts fit, heavy ASTM A194, Grade 2H hexagon, semi-finish Spiral Gaskets wound asbestos Spiral Wound Mfg. or Type Mfg. No. w/AISI 304 SS windings Thread Lubricant Conform API to No.Bulletin Mfg. 5A2 NOTES: 1 For glycol service, all valves and fittings shall be flanged or socketweld. . 2. API 5L, Grade B, Seamless may be substituted if ASTM A106, Grade B, Seamless is not available. 3. Studs and nuts shall be hot-dip galvanized in accordance with ASTM A163. 4. Fittings and flanges that do not require normalizing in accordance with ASTM A105, due to size or pressure rating, shall be normalized when used for service temperatures from -20°F to 60°F. Fittings and flanges shall be marked HT, N, * or with some other appropriate marking to designate normalizing. COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 58. A P I R P U L 4 E 91 W 0732290 0099537 8 m RP 14E:Offshore Production Platform Piping Systems 67 APPENDIX D LIST OF EQUATIONS EquationDescription Number Page 2.1 Flow Velocity in Liquids Lines................................................................... 15 2.2 Pressure Drop in Liquid Lines ................................................................... 15 2.3 Reynold’s Number .............................................................................. 15 2.4 Available Net Positive Suction Head (NPSHa) .................................................... 20 2.5 Acceleration Head .............................................................................. 20 2.6 General Pressure Drop Equation................................................................. 21 2.7 General Pressure Drop Equation................................................................. 21 2.8 General Pressure Drop Equation., ............................................................... 21 2.9 General Pressure Drop Equation ................................................................. 21 2.10 Weymouth Equation ............................................................................ 22 2.11 Panhandle Equation............................................................................. 22 2.12 Spitzglass Equation ............................................................................. 22 2.13 Gas Velocity Equation ........................................................................... 22 2.14 Empirical Equation. ............................................................................ 23 2.15 Density of a Gas/Liquid Mixture ................................................................. 23 2.16 Minimum Pipe Cross-Sectional Area Required to Avoid Fluid Erosion ............................. 23 2.17 Pressure Drop in Two-Phase Lines ............................................................... 23 2.18 Liquid Plus Vapor Rate a Two-Phase Line (Weight in Flow) ....................................... 23 2.19 Minimum Pipe WallThickness ................................................................... 25 2.20 Stress Analysis Criteria for a Two-Anchor System ................................................ 25 2.21 Therman Expansion of Piping ................................................................... 25 3.1 Pressure DropAcross a Valve in Liquid Service .................................................. 30 3.2 Pressure Drop Across a Valve in Gas Service ..................................................... 30I COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 59. A P I RPw14E 91 m 0732290 0099540 4 H 58 Institute Petroleum American APPENDIX E LIST OF FIGURES Figure Number Title Page 1.1 Example System Process Denoting and Pressure Changes Flange Valve Rating 12 2.1Velocity in LiquidLines _ _ _ _ _ I _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ 17 Drop 2.2 Pressure . . . . 18 Chart Factor 2.3 Friction (Modified Moody Diagram) 19Velocity 2 6 Erosional . 24 5.1.A Example Schematic Drawing of Piping and Accessories for Flowlines and Manifolds ThatRated Are for Not Wellhead Pressure ________ 36 _______.____ _._._ 5.1.B Example Schematic Drawing of Piping and Accessories for Flowlines Rated Manifolds Are and That for Wellhead Pressure ~ ____ 37 5.2 Example Schematic Drawing of Three-phase Process VesselShowingVarious Accessories 39 B1.l Acceptable Butt Welded Joint Design for Unequal Wall Thicknesses ___ .__.___._____.53 _____._~ ~ ~ C.1 Example Index for Pipe, Valves and Fittings Tables ~ 54 _________.___ ~ C.2 Example Table Pipe, Valves Fittings and ~ __________ ___________ ____ ~ ~ ____ 55 ~ COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 60. RP 14E:Offshore Systems Production Piping Platform 69 APPENDIX F LIST OF TABLES Table Number 11 . Qualitative Weight GuidelinesCorrosion forLoss ____ of Steel _____ ~ ____ 13 21 . Typical 15 2.2 Equivalent Length of 100 Percent Valves in Opening Feet Fittings and 16 2.3 Typical Flow Velocities (For reciprocating and centrifugal pump piping) ~ 21 2.6 MaximumAllowableWorkingPressures - Platform Piping (Forvarioussizesandwallthickness of ASTM A106, Grade B, seamless pipe) _____ 27 .. ~ ~ 41 . BranchConnectionSchedule - Welded Plplng 33 6.1 Thickness Hot Insulation Typical 44 6.2 Typical Cold Thickness Insulation ____ _______________ _______ 44 6.3 Typical Insulation for Personnel Protection (Applicable hot surface temperature ranges)--_------ 44 7.1 Minimum Extent of Radiographic Weld Examination carbon material) (For steel ___ ___ 45COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 61. A P I R P * l Y E 71 E 0732270 0099542 A E Order No. 81 1-07185 Additional copies availablefrom AMERICAN PETROLEUMINSTITUTE Publications and Distribution Section 1220 L Street, NW 4’ 1. Washington, DC 20005 (202) 682-8375COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services