1、Recommended Practice for Design and Installation of Offshore Production Platform Piping SystemsAPI RECOMMENDED PRACTICE 14EFIFTH EDITION, OCTOBER 1991REAFFIRMED, JANUARY 2013Issued by AMERICAN PETROLEUM INSTITUTE Production Department FOR INFORMATION CONCERNING TECHNICAL CONTENTS OF THIS PUBLICATION
2、 CONTACT THE API PRODUCTION DEPARTMENT, SEE BACK COVER FOR INFORMATION CONCERNING HOW TO OBTAIN ADDITIONAL COPIES OF THIS PUBLICATION. 1201 MAIN STREET. SUITE 2535. DALLAS, TX 75202-3994 - (214) 746-3841. Users of this publication should become completely familiar with its scope and content. This pu
3、blication is intended to supplement rather than replace individual engineering judgment. OFFICIAL PUBLICATION REO. U.S. PATENT OFFICE Copyright 0 1991 American Petroleum Institute 2 Amencan Petroleum Institute API RECOMMENDED PRACTICE FOR DESIGN AND INSTALLATION OF OFFSHORE PRODUCTION PLATFORM PIPIN
4、G SYSTEMS TABLE OF CONTENTS Page POLICY _-_-_- 6 FOREWORD 7 DEFI“IONS 7 SYMBOLS 8 -_ SECTION 1 - GENERAL 9 Scope 9 Code for Pressure 9 Policy _c_ _ 9 Industry Codes, Guides and 9 American .Iron and Steel Institute 9 American National Standards Institute 9 American Petroleum Institute _I_-_- 10 Ameri
5、can Society for Testing and Materials 10 American Society of Mechanical Engineers 10 National Association of Corros!on Engineers 10 National Fire Protection Association 10 Gas Processors Suppliers Association-. 10 Hydraulics Institute 10 Governmental Rules and Regulations 10 Demarcation Between Syst
6、ems with Different Pressure Ratings-_ 11 Corrosion 13 General 13 Weight Loss Corrosion A 13 Sulfide Stress ._ 13 Chloride Stress 13 Application of NACE MR-01-75 13 SECTION 2 - PIPING DESIGN I-_ 14 Pipe 14 Non-Corrosive Hydrocarbon. Service 14 Corrosive Hydrocarbon 14 Sulfide Stress Cracking 14 Utili
7、ties Service 14 Tubing 1 14 Sizing Criteria - General_.-_-_-_-_- . 14 Slung Critena for Liquid 15 General 15 15 Pump Piping Sizing Criteria for Single-phase Gas Lines 21 General Pressure Drop Equation 21 Empirical Pressure Drop 21 Gas Velocity Equation _- 22 Compressor Piping ._l_l_- 23 General Note
8、s _I_I_-_-_ 23 23 Erosional Velocity _-_-_.- 23 Minimum Velocity 23 Pressure Drop 23 Pipe Wall Thicknesses 25 Joint Connections . 25 Expansion and Flexibility 25 Start-up Provisions _I_-_- 25 References _I_-_- 26 . Sizing Criteria for Gasniquid Two-Phase Lines RP 14E: Offshore Production Platform Pi
9、ping Systems 3 TABLE OF CONTENTS (Continued) Page 29 General 29 Types of Valves 29 Ball Valves 29 Gate Valves 29 Plug 29 _ Butterfly 29 Globe Valves 29 Diaphragm (Bladder) 29 Needle Valves 30 Check Valves 30 Valve 30 Valve Pressure and Temperature 30 Valve Materials 31 Non-Corrosive 31 Corrosive Ser
10、vice 31 Chloride Stress Cracking Service 31 Sulfide Stress Cracking 31 References _I_-_- 31 SECTION 3 - SELECTION OF VALVES SECTION 4 - FIlTINGS AND FLANGES 32 General 32 Welded Fittings 32 Screwed 32 Branch Connections 32 Flanges 32 General 32 Gaskets 33 Flange Protectors 34 Bolts and Nuts - 34 Pro
11、prietary 34 Special Requirements for Sulfide Stress Cracking Service 34 Erosion 34 References 34 SECTION 5 - DESIGN CONSIDERATIONS FOR . PARTICULAR PIPING SYSTEMS _I_ 35 General 35 Wellhead Accessory Items 35 Sampling and Injection Connections 35 Chokes 35 Flowline and Flowline Accessories _I_- 35 F
12、lowline Pressure 35 Flowline Orifice Fitting 35 Flowline Heat Exchanger 35 Flowline Check Valve 35 Flowline 35 American Petroleum Institute 4 TABLE OF CONTENTS (Continued) SECTION 6 - CONSIDERATIONS OF RELATED ITEMS 42 General 42 Layout 42 Elevations 42 Piping Supports 42 Other Corrosion Considerati
13、ons 42 42 Types of Platform Piping Coating Systems 42 Selection of Platform Piping Coating Systems 42 Risers 42 42 42 Process Water 42 Protective Coatihgs . 42 42 Compatibility of Materials Non-Destructive Erosion and/or Corrosion Surveys- 43 43 Cathodic Protection _-_I_ Thermal Insulation 43 Noise
14、43 Pipe, Valves and Fittings Tables ._ _ _ _ _ _ 43 Inspection, Maintenance however, special welding procedures and Aose supervision are necessary when using API 5L, Grade X46, or higher. Many of the grades of pipe listed in ANSI B31.3 are suitable for non-corrosive hydrocarbon service. The followin
15、g types or grades of pipe are specificall excluded from hydrocarbon ser- vice by ANSI 531.3: (i) All grades of ASTM A120. (2) Furnace lap weid and furnace buttweld. (3) Fusion weld per ASTM A134 and A139. (4) Spiral weld, except API 5L spiral weld. b. Corrosive Hydrocarbon Service. Design for cor- r
16、osive hydrocarbon service should provide for one or more of the following corrosion mitigating practices: (1) chemical treatment: (2) corrosion re sistant allo ; (3) protective coatings (See Para- h 6.5.byOf these, chemical treatment of the in contact with carbon steels is by far the most common pra
17、ctice and is generally recom- mended. Corrosion resistant alloys which have proven successful in similar applications (or by suitable laboratory tests) may be used. If such alloys are used, careful consideration should be given to welding rocedures. Consideration should also be given to t!e possibil
18、ity of sulfide and.chlo- ride stress cracking (See Paragraphs 1.7.c and 1.7.d). Adequate provisions should be made for corrosion monitoring (coupons, probes, spools, etc.) and chemical treating. c. Sulfide Stress Cracking Service. The following guidelines should be used when selecting pipe if sulfid
19、e stress corrosion cracking is anticipated: (i) Only seamless pipe should be used unless quality control applicable to this service has been exercised in manufacturing ERW or SAW pipe. (2) Cold expanded pipe should not be used unless followed by normalizing, quenching and tempering, tempering, or he
20、at treat- ment as described in 2.l.c(4). (3) Carbon and alloy steels and other materials which meet the property, hardness, heat treatment and other re uirements of NACE MR-01-76 are acceptabpe for use in sulfide stress cracking service. (4) Materials not meeting the metallurgical re- quirements of
21、NACE MR-01-75 may be used; however, usage should be limit- to appli- cations or systems in which the external environment and the process stream can be continuous1 maintained assure. freedom from suifid stress cracking, or limited to those materials for which adequate data exists to demonstrate resi
22、stance to sulfide or chloride stress cracking in the application or system environments to which the m-aterials are exposed, (See MR-01-75). The most commonly used pipe grades which will meet the above guidelines are: ASTM A106, Grade B; ASTM A333, Grade 1; and API 5L. Grade B, seamless. API 5L X gr
23、ades are also acce table: however, welding presents s ecial YbLms. To enhance toughness and reduce Erittle racture tendencies, API 5L pipe should be nor- malized for service temperatures below 30“ F. ASTM A333. Grade 1. is a cold service DiDinP material and should have adequate notch Gu 6 ness in th
24、e temperature range covered by this ftP (-20“ to 650F). d. Utilities Service. Materials other than carbon steel are commonly used in utilities service. If, however, steel pipe is used that is of a type or grade not acceptable for hydrocarbon service in accordance with Paragraph 2.l.a, some defi- nit
25、e marking system should be established to prevent such pipe from accidentally being used in hydrocarbon service. One way to accomplish this would be to have all such pipe galvanized. e. Tubing. AISI 316 or AISI 316L stainless steel, seamless or electric resistance welded tubing is preferred for all
26、hydrocarbon service, and air service exposed to sunlight. Tubing used for air service not exposed to sunlight, or instrument tub- ing used for gas service contained in an enclosure, may be made of other materials. If used, synthetic tubing should be selected to withstand degradation caused by the co
27、ntained fluids and the tempera- ture ta which it may be subjected. 2.2 Sizing Criteria - General. In determining the diameter of pipe to be used in platform piping sys- tems, both the flow velocity and pressure drop should be considered. Sections 2.3, 2.4 and 2.5 present equa- tions for calculating
28、pipe diameters (and graphs for rapid approximation of pipe diameters) for liquid lines, single-phase gas lines, and gas/liquid two-phase lines, respectively. Many companies also use compu- ter programs to facilitate piping design. a. When determining line sizes, the maximum flow rate expected during
29、 the life of the facility should be considered rather than the initial flow rate. It is also usually advisable to add a surge factor of 20 to 50 percent to the antici- pated normal flow rate, unless surge expecta- tions have been more precisely determined by pulse pressure measurements in similar sy
30、stems or by specific fluid hammer calculation. Table 2.1 presents some typical surge factors that may be used if more definite information is not available. RP 14E: Offshore Production Platform Piping Systems 15 In large diameter flow lines producing liquid- vapor phase fluids between platforms thro
31、ugh riser systems, surge factors have been known to exceed 200% due to slug flow. Refer. to liquid-vapor slug flow programs generally available to Industry for evaluation of slug flow. TABLE 2.1 TYPICAL SURGE FACTORS Service Factor Facility handling primary production from its own platform 20% Facil
32、ity handling primary production from another platform or remote well in less than 150 feet of water Facility handling primary production from another platform or remote well in greater than 150 feet of water 40% its own platform 40 % 30% Facility handling gas lifted production from Facility handling
33、 gas lifted production from another platform or remote well 5090 b. Determination of pressure drop in a line should include the effect of valves and fittings. Manu- facturers data or an equivalent length given in Table 2.2 may be used. c. Calculated line sizes may need to be adjusted in accordance w
34、ith good engineering judgment. 2.3 Sizing Criteria For Liquid Lines. a General. Single-phase li uid lines should be sized primarily on the basis 01 flow velocity. For lines transporting liquids in singlephase from one pres- sure vessel to another by pressure differential, the flow veloci should not
35、-exceed 15 feet/second at of the control valve. If practical, flow velocity should not be less than 3 feet/second to minimize de ition of sand and other solids. At these flow veEties. the overall ressure drop in the iping will usually be small. host of the pressure but the pump required NPSH is typi
36、cally higher than for a centrifugal pump because of pressure drop across the valves and pressure drop caused by pulsa- tion in the flow. Similarly, the available NPSH supplied to the pump suction must account for the acceleration in the suction piping caused by the pulsating flow, as well as the fri
37、ction, velocity and static head. (2) The necessary available pressure differen- tial over the pumped fluid vapor pressure may be defined as net positive suction head available ( NPSH.) . It is the total head in feet absolute determined at the suction nozzle, less the vapor pressure of the liquid in
38、feet absolute. Available NPSH should always equal or exceed the pumps required NPSH. Available NPSH for most pump applications may be calculated using Equation 2.4. divided by 1488. 16 American Petroleum Institute , t/s : a/v s O .- o1 pc .- o, 2/i = O/P */i =alp 2/i = a/v t/i: O/P no li3 OS RP 14E:
39、 Offshore Production Platform Piping Systems 17 E O 1 .- +I w c.i O 2 LIQUID FLOW VELOCITY, FEETBECOND American Petroleum Institute 18 8 PRESSURE DROP PSI/lOO FEET RP 14E: Offshore Production Platform Piping Systems 19 20 American Petroleum Institute NPSH. = hp - hvpa + hst - hi - hvh - ha Eq. 2.4 w
40、here : hp = absolute pressure head due to pres- sure, atmos heric or otherwise, on surface of quid going to suction, feet of liquid. hrr = the absolute vapor pressure of the liquid at suction temperature, feet of liquid. hst = static head, positive or negative, due to liquid level above or below dat
41、um line (centerline of pump), feet of liquid. hi = friction head, or head loss due to flowing friction in the suction pip- ing, including entrance and exit losses, feet of liquid. Vi2 2g hvh = velocity head= - , feet of liquid. hi = acceleration head, feet of liquid. Vi = velocity of liquid in pipin
42、g, feet/ second. g = gravitational constant (usually 32.2 feet I secondz) . (3) For a centrifugal or rotary pump, the accel- eration head, hi, is zero. For reciprocating pumps, the acceleration head is critical and may be determined by the following equa- tion from the Hydraulics Institute: Eq. 2.5
43、where: h, = acceleration head, feet of liquid. L = length of suction line, feet (actual length, not equivalent length). Vi = average liquid velocity in suction line, feetisecond. Rp = pump speed, revolutionsiminute. C = empirical constant for the type of pump: = .200 for simplex double acting; = .20
44、0 for duplex single acting; = .116 for duplex double acting; = .O66 for triplex single or double act- ing; = .O46 for quintuplex single or double acting ; = .O28 for septuplex single or double acting. NOTE: The constant C will vary from these values for unusual ratios of connecting rod length to cra
45、nk radius. K = a factor representing the reciprocal of the fraction of the theoretical acceleration head which must be provided to avoid a noticeable dis- turbance in the suction piping: = 1.4 for liquid with almost no eom- pressibility (deaerated water) ; = 1.6 for amine, glycol, water; = 2.0 for m
46、ost hydrocarbons; = 2.5 for relatively compressible liq- uid (hot oil or ethane). g = gravitational constant (usually 32.2 feet /secondz). It should be noted that there is not uni- versal acceptance of Equation 2.5 or of the effect of acceleration head (See References b, c and d, Section 2.10). Howe
47、ver, Equation 2.5 is believed to be a conservative basis which will assure adequate provision for acceleration head. - (4) When more than one reciprocating pump is operated simultaneously on a common feed line, at times all crankshafts are in phase and, to the feed system, the multiple pumps act as one pump of that type with a capacity equal to that of all pumps com- bined. In this case, the maximum instan- taneous ve
