Nrf 013 Pemex 2009 English

Document NumberNRF-013-PEMEX-2009

December 21th, 2009PETRÓLEOS MEXICANOS AND SUBSIDIARY ENTITIES STANDARDIZATION

COMMITTEE

Page 1 of 63PEMEX EXPLORATION AND PRODUCTION TECHNICAL STANDARDIZATION

SUB-COMMITTEE

DESIGN OF SUBSEA PIPELINES IN THE GULF OF MEXICO

This reference cancels and replaces NRF-013-PEMEX-2005 of March 18th, 2006.

PEMEX EXPLORATION AND PRODUCTION TECHNICAL

STANDARDIZATION COMMITTEE

DESIGN OF SUBSEA PIPELINES IN THE GULF

OF MEXICO

NRF-013-PEMEX-2009

Rev.: 10Page 2 of 63

APPROVAL SHEET

PREPARED BY:

ENG. LUIS ORTIZ HERNÁNDEZ

WORK GROUP COORDINATOR

PROPOSED BY:

ENG. JESÚS HERNÁNDEZ SAN JUAN

VICE PRESIDENT OF PEMEX EXPLORATION AND PRODUCTION TECHNICAL STANDARDIZATION SUB-COMMITTEE

APPROVED BY:

DR. RAÚL A. LIVAS ELIZONDO

PRESIDENT OF PETRÓLEOS MEXICANOS AND SUBSIDIARY ENTITIES STANDARDIZATION COMMITTEE

CONTENTS

PETRÓLEOS MEXICANOS AND SUBSIDIARY ENTITIES


DESIGN OF SUBSEA PIPELINES IN THE GULF OF

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CHAPTER PAGE

0. INTRODUCTION.....................................................................................................................7

1. PURPOSE................................................................................................................................9

2. SCOPE......................................................................................................................................9

3. APPLICATION FIELD.............................................................................................................9

4. UPDATING.............................................................................................................................13

5. REFERENCES......................................................................................................................13

6. DEFINITIONS........................................................................................................................14

7. SYMBOLS AND ABBREVIATIONS....................................................................................17

8. DEVELOPMENT....................................................................................................................18

8.1 Subsea Pipeline Design................................................................................................18

8.1.1 Design considerations.................................................................................................18

8.1.1.1 User basis...........................................................................................................18

8.1.1.2 Design basis.......................................................................................................19

8.1.1.3 Route selection...................................................................................................19

8.1.1.4 Geophysical and geotechnical studies............................................................20

8.1.1.5 Materials..............................................................................................................20

8.1.1.5.1 Pipe......................................................................................................................20

8.1.1.5.2 Accessories........................................................................................................20

8.1.1.6 Stress Loads.......................................................................................................20

8.1.1.6.1 Pressure..............................................................................................................20

8.1.1.6.2 Live loads............................................................................................................20

8.1.1.6.3 Dead loads..........................................................................................................20

8.1.1.6.4 Dynamic loads....................................................................................................21

8.1.1.6.5 Pressure increase due to fluid expansion.......................................................21

8.1.1.6.6 Loads due to contraction and thermal expansion..........................................21

8.1.1.6.7 Interaction soil-pipe............................................................................................21

8.1.1.7 Riser.....................................................................................................................21

8.1.1.8 Expansion Spool................................................................................................22




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8.1.1.9 Connections, accessories, flanges and valves..............................................22

8.1.1.10 Monitoring spool and transition piece..............................................................22

8.1.1.11 Pig traps..............................................................................................................23

8.1.1.12 Minimum separation between regular pipelines............................................23

8.1.1.13 Concrete coating................................................................................................23

8.1.1.14 Burial of the pipeline..........................................................................................23

8.1.1.15 Marine growth.....................................................................................................23

8.1.1.16 Subsea crossing.................................................................................................24

8.1.1.17 Free spans..........................................................................................................24

8.1.1.18 Vorticity................................................................................................................24

8.1.1.18.1 Oscillations in parallel direction to the velocity vector...............................27

8.1.1.18.2 Oscillations in perpendicular direction to the velocity vector....................27

8.1.1.19 Fatigue.................................................................................................................27

8.1.1.20 Expansion and flexibility....................................................................................28

8.1.1.21 Branch connections...........................................................................................29

8.1.1.22 Hydraulic Analysis..............................................................................................29

8.1.1.23 Corrosion.............................................................................................................29

8.1.1.23.1 External corrosion..........................................................................................29

8.1.1.23.1.1 Anti-corrosive coating...................................................................................29

8.1.1.23.1.2 Cathodic protection.......................................................................................30

8.1.1.23.2 Internal corrosion...........................................................................................30

8.1.2 Subsea pipeline classification..............................................................................31

8.1.2.1 Pipelines transmitting flammable and/or toxic gases...................................31

8.1.2.2 Pipelines transmitting flammable and/or toxic liquid....................................31

8.1.2.3 Pipelines transmitting non-flammable or non-toxic fluids............................32

8.1.3 Mechanical effects.................................................................................................32

8.1.3.1 Internal Pressure................................................................................................32

8.1.3.1.1 Required minimum thickness...........................................................................33

8.1.3.1.1.1 Design thickness............................................................................................34




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8.1.3.1.1.2 Corrosion tolerance.......................................................................................34

8.1.3.1.1.3 Fabrication tolerance.....................................................................................34

8.1.3.1.1.4 Thickness for high temperature in fixed restricted pipelines....................35

8.1.3.2 Revision of thickness for other conditions......................................................36

8.1.3.2.1 Longitudinal tension (Tu)..................................................................................37

8.1.3.2.2 External pressure...............................................................................................37

8.1.3.2.2.1 Collapse pressure (Pc):.................................................................................37

8.1.3.2.2.2 Buckling propagation (Pp):...........................................................................38

8.1.3.2.3 Bending moment (Mu).......................................................................................39

8.1.3.2.4 Global buckling (Cg):.........................................................................................40

8.1.3.2.5 Formulation of design for combined load status............................................41

8.1.3.2.5.1 Tension and bending moment (Tu-Mu).......................................................41

8.1.3.2.5.2 Axial load, bending moment and collapse pressure (Tu, Mu-Pc)............42

8.1.4 Hydrodynamic stability..........................................................................................42

8.1.4.1 Buoyancy analysis of buried pipeline..............................................................45

8.1.4.2.1 Wave height and current velocity.....................................................................46

8.1.4.2.2 Swell and current direction...............................................................................47

8.1.4.2.2.1 Bay of Campeche and Litoral Tabasco.......................................................47

8.1.4.2.2.2 North Zone and Lankahuasa........................................................................47

8.1.4.3 Oceanographic parameters for a return period of 100 years.......................48

8.1.4.3.1 Wave height and current velocity.....................................................................48

8.1.4.3.2 Direction of the swell and current....................................................................48

8.1.4.3.2.1 Bay of Campeche and Litoral Tabasco.......................................................48

8.1.4.3.2.2 North Zone and Lankahuasa........................................................................48

8.1.5 Design document submission..............................................................................48

9. RESPONSIBILITIES.............................................................................................................49

9.1 Petróleos Mexicanos and subsidiary entities.............................................................49

9.2 Pemex Exploration and Production Technical Standardization Sub-committee. . .50

9.3 Contractors.....................................................................................................................50




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10. COMPLIANCE WITH MEXICAN OR INTERNATIONAL STANDARDS....................50

11. BIBLIOGRAPHY................................................................................................................50

12. ANNEX................................................................................................................................54

Annex A. Oceanographic information for the Gulf of Mexico...............................................54

Annex B. Conversion of the gas and light oil production in thousands of barrels of heavy crude oil equivalent...................................................................................................................61




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0. INTRODUCTION

The recent development of oil fields in the Gulf of Mexico has involved an increase in the temperature and pressure of the fluids collected and transported to the relevant sites, which has caused an important increment in the compression strengths in straight parts of the pipeline due to thermic restriction caused by its interaction with the soil. Consequently, the pipeline tends to release the compression strengths while it experiments a configuration of secondary balance, i.e. buckling or weaving happens. The conditions on which the lateral or upheaval buckling happens depend on the various factors, such as soil strength, submerged weight, characteristics of the cross-section and the final straightness condition after the pipe is laid.

Consequently, the design methodologies for high temperature (TA) and high pressure (PA) pipelines differ noticeably from the traditional design of subsea pipelines; therefore, this reference standard establishes the criteria that engineering designers of subsea pipelines shall take into account such as: criteria based on stresses, criteria based on buckling and use of mechanical devices (not expansion joints) to control lateral shifting. This is applicable to pipelines that operate at: high temperatures up to 150°C (302°F), pressures up to 351,5 Kg/cm2 (5 000 lb/in2) and water depth up to 200m (656,17 ft.).

Additionally to the structural design criteria for TA and PA, the oceanographic parameters for hydrodynamic stability design in the Bay of Campeche, Litoral Tabasco, North Zone and Lankahuasa were included. In the case of the Bay of Campeche and Litoral Tabasco, besides updating the parameters, the depth water was extended to 200 m (656,17 ft.) and in the case of the North Zone and Lankahuasa, only the oceanographic parameters were updated and the depth continues to be 100m (328,09 ft.).

This reference document was prepared in consideration and adherence to:

Metrology and Standardization Federal Law, and its Regulation Public Works and Related Services Law, and its Regulation Acquisitions, Leases and Services for the Public Sector Law, and its Regulation General Rules for Hiring and Execution of Public Works. Guide for writing, structuring and presentation of Mexican standards NMX –Z-13/1-

1997. Guidelines for the Issuance of Petróleos Mexicanos and Subsidiary Entities

Reference Standards. Policies, bases and guidelines in terms of public works and services related to the

same for Petróleos Mexicanos, its Subsidiary Entities and Subsidiary Companies.




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The following Pemex Subsidiary entities and Institutions participated in the preparation of this document:

Pemex Exploration and Production (PEP) Petróleos Mexicanos. Instituto Mexicano del Petróleo (IMP). Supervisión y Desarrollo de Proyectos Marinos S.A. de C.V. Sacmag de México, S.A. de C.V.




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1. PURPOSE

To establish the technical and documental requirements that shall be met for hiring the design engineering services for hydrocarbon transmission subsea pipelines located in the Gulf of Mexico.

2. SCOPE

This reference standard establishes the minimal requirements for the design of subsea carbon steel pipelines for the following conditions:

Temperature up to 150°C -8302°F) Pressure up to 351, 5 kg/cm2 (5 000 lb/in2) Depths up to 200 m (656, 17 ft.) in the Bay of Campeche and Litoral Tabasco. Depths up to 100 m (328, 09 ft.) in North Region and Lankahuasa.

The above applies to pipelines laid either between platforms, or with beach approach as well as interconnections with existing pipelines or subsea wells in order to guarantee their integrity from various mechanical and hydrodynamic effects with the purpose to reduce the possibility of losing human lives, ecological damages, economical losses and physical damages of the facilities during their service life. It covers general considerations for the design as well as the classification of the pipelines according to the zone and fluid type that is transported. The expressions and safety factors that shall be used for the different requests to which the line is subjected are indicated. It includes the criteria for the hydrodynamic stability for the installation and operational phase, and the oceanographic parameters that shall be used according to the different regions in the Gulf of Mexico.

This standard is not applicable for flexible or fabricated pipes made from another material like plastic reinforced with glass fiber.

3. APPLICATION FIELD

This standard is of general application and compulsory observance when hiring services, purpose of the same, carried out by work centers of Petróleos Mexicanos and Subsidiary Entities. Thus, it shall be included in the hiring procedures: public bid, bid call for at least three people or direct award as part of the requirements to be met by the supplier, contractor or bidder.




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This standard is applicable in the design of subsea pipelines located in the Gulf of Mexico, in depths and zones delimited by the coordinates that are indicated below and that are shown in Figure 1.

Geographic coordinates.

N19° 00’, W93° 30’, N18° 26’ and W92° 00’ (Litoral Tabasco) to 200m (656, 17 ft.). N20° 10’, W92° 40’, N18° 55’ and W91° 55’ (Bay of Campeche) to 200m

(656,17ft.). N20°42’, W97°31’, N22°18’ and W96° 56’ (North Zone) to 100m (328, 09 f.). N20° 30’, W96° 53’, N20° 40’ and W96° 39’; N20° 10’, W96° 14’ and N19° 59’,

W96° 29’ (Zone Lankahuasa) to 100m (328,09ft).

UTM coordinates, according to North American Datum of 1927, information based on the Clarke ellipsoid 1866.

UTM coordinates:

X=447 373, 74; Y=2 100 776, 37; X=605 606, 89; Y= 2 038 297, 81 (Litoral Tabasco).

X=534 832, 24; Y= 2 229 827, 27; X=614 084, 44; Y= 2 091 831,16 (Bay of Campeche)

X= 654 482, 43; Y= 2 289 517, 91; X=712 908, 04; Y= 2 467 346, 73 (North Zone) X= 720 748, 47; Y= 2 268 106, 98; X=744 826, 52; Y=2 286 894, 87; X=789 192, 66; Y=2 232 200, 77; X= 763 353, 54; Y=2 211 483, 01; (Zone

Lankahuasa).




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Figure 1. Standard application zone

The design guidelines that are established in this document apply for the zoning of subsea pipeline indicated in Figure 2.




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DETAIL 1

Note: In the absence of pig trap, the subsea pipeline is considered up to the cut-off valve 1 and 3.

Figure 2. Zoning of a subsea pipeline




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4. UPDATING

Suggestions for review and update of this standard will be sent to the Secretary of PEP Technical Standardization Subcommittee, who will program the updating according to the appropriateness of the same; and if applicable, he will go through the Petróleos Mexicanos and Subsidiary Entities Standardization Committee, which will register it in the Standardization Annual Program of Pemex. However, this standard will be reviewed and updated at least every 5 years or before, if suggestions and change recommendations are applicable.

Proposals and suggestions shall be addressed to:

Pemex Exploración y ProducciónSubcomité Técnico de NormalizaciónBahía de Ballenas #4, Edificio “D”, Planta Baja. Col. Verónica Anzures. 11311 México, D.F.Direct Telephone: 19-44-92-86Switchboard: 19-44-25-00, extension: 3-26-90 and 3-80-80.E-mail: [email protected]

5. REFERENCES

NOM-008-SCFI-2002 Sistema general de unidades de medida (General system of measurement units).

ISO 14723:2001 Petroleum and natural gas industries- Pipeline transportation systems- Subsea pipeline valves.

NRF-001-PEMEX-2007 Tubería de acero para recolección y transporte de hidrocarburos. (Steel pipeline for collection and transmission of hydrocarbons).

NRF-005-PEMEX-2000 Protección interior de ductos con inhibidores. (Pipeline internal protection with inhibitors).

NRF-026-PEMEX-2008 Protección con recubrimientos anticorrosivos para tuberías enterradas y/o sumergidas. (Anti-corrosive coating protection for buried and/or submerged pipelines).

mailto:[email protected]




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NRF-030-PEMEX-2006 Diseño, construcción, inspección y mantenimiento de ductos terrestres para transporte y recolección de hidrocarburos. (Design, construction, inspection and maintenance of for collection and transmission land pipelines).

NRF-033-PEMEX-2003 Lastre de concreto para tuberías de conducción. (Concrete ballast for transmission pipelines).

NRF-047-PEMEX-2008 Diseño, instalación y mantenimiento de los sistemas de protección catódica. (Design, installation and maintenance of cathodic protection systems).

NRF-053-PEMEX-2006 Sistemas de protección anticorrosiva a base de recubrimientos para instalaciones superficiales. (Coating based anti-corrosive protection systems for surface facilities).

NRF-096-PEMEX-2004 Conexiones y accesorios para ductos de recolección y transporte de hidrocarburos. (Connections and fittings for hydrocarbon collection and transmission pipelines).

NRF-178-PEMEX-2007 Trampas de diablos en plataformas marinas. (Pig traps for offshore platforms).

NRF-211-PEMEX-2008 Válvulas de compuerta y bola en líneas de transporte de hidrocarburos. (Gate and ball valves in hydrocarbon transmission pipelines).

NRF-229-PEMEX-2008 Estudios geofísicos y geotécnicos para la instalación de plataformas marinas y líneas submarinas. (Geophysical and geotechnical surveys for offshore platforms and subsea pipelines the installation).

6. DEFINITIONS

6.1 Clamps: Fitting used to support the riser to the platform leg.

6.2 Anchor clamp: Fitting that provides completely restriction for shifting and turns in the riser.

6.3 Guiding clamp: Fitting that does not restrict shifting of the longitudinal axis of the riser.




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6.4 Subsea manifold: Terminal facility with connection arrangements for additional facilities (see figure 2).

6.5 Monitoring spool: Pipe section with a shop joint in its central part, which helps to identify readings of smart pigs.

6.6 Free span: Section or length of the pipe that is not supported by any element that limits its movement, or on the seabed.

6.7 Subsea crossing: Place where two subsea pipelines cross in their route.

6.8 Expansion spool: Pipe section that connects the riser to the regular pipeline, which function is to damp the displacements caused by expansion and movement of the platform (see figure 2).

6.9 Fender: Structure that is fixed to the platform which protects the riser against impacts.

6.10 Pig: Device or equipment that is inserted in the pipeline for cleaning and inspection purposes.

6.11 Pipeline or line: Pipe system with different components such as: valves, flanges, fittings, studs, safety or relief devices, among others, subjected to pressure and through which hydrocarbons are transported (Liquid or Gases) and other fluids.

6.12 Riser: Pipe section that connects a pig trap or pipeline on deck to the expansion spool (see figure 2).

6.13 Equivalent: National or foreign regulatory document (Regulation, Code, Specification, Standard, or Recommended Practice) that is not a Mexican Official Standard (NOM), Mexican Standard (NMX), or International Standard (ISO or IEC) that includes, as minimum, the parameters and concepts that are required to be evaluated, and that are established as requirements, besides of values and characteristics (physical, chemical, physicochemical, mechanical or any other nature) equal or better than the reference document, to which this standard makes reference.

6.14 Stress: It is the relation between the applied force and the application area expressed in N/mm2 or lb/in2.

6.15 Specified Minimum Yield Stress (SMYS): It is the resistance to the minimum yield indicated in the specifications by the pipe manufacturer in N/mm2 (lb/in2).

6.16 Specified Minimum Ultimate Tensile Strength (SMTS): It is the ultimate resistance to tension indicated in the specifications by the pipe manufacturer in N/nm2

(lb/in2)




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6.17 Installation phase: It is the period of time starting from the lay of the subsea pipeline to the beginning of the fluid transportation.

6.18 Operation phase: It is the period of time from the start of the fluid transportation to the end of the service life of the subsea pipeline.

6.19 Isolating Joint: Fitting used to insulate electrically the pipeline in the air from the submerged one.

6.20 Regular pipeline: Pipeline section between the expansion spools (see figure 2).

6.21 Restricted pipeline: Pipeline in which the soil or supports restrict axial or lateral shifting. Any buried section is considered as a restricted pipeline. The riser and expansion spool are not considered as restricted pipelines.

6.22 Global buckling: Buckling mode which affects a determined section of the pipeline. It generally includes many welded joints and it does not imply buckling of the cross-section of the pipeline.

6.23 Transition piece: Pipe section of a minimal length equal to its diameter and the same specification of the pipeline material, which is used to join sections of different thickness.

6.24 High pressure: Pipeline operating pressure starting from 105, 5 kg/cm2 (1 500 lb/in2) to 351, 5 kg/cm2 (5 000 lb/in2).

6.25 Design pressure: It is the internal pressure to which the pipeline is designed and it is equal to 1. 1 times the maximum operating pressure.

6.26 Maximum operating pressure: It is the maximum pressure to which a pipeline is expected to be subjected during its operation.

6.27 Hydrostatic pressure: It is the pressure resulting from the hydrostatic water column measured from the seabed to the middle sea level plus the filler material on the pipeline, in cases of buried pipelines.

6.28 Hydrodynamic pressure: It is the pressure resulting from the water column corresponding to the tide hydrodynamic conditions, plus the 70% of the hydrodynamic water column due to the swells related to the recurrence period of the accepted design.

6.29 External pressure (Pext): It is the sum of the hydrostatic pressure plus the hydrodynamic pressure.




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6.30 Internal pressure (Pint): It is the pressure produced in the internal walls of the pipeline by the fluid being transported.

6.31 Collapse pressure (Pc): It is the characteristic capability of the pipeline against an external overpressure.

6.32 Propagation pressure (Pp): It is the characteristic capability to continue the buckling propagation along the pipeline.

6.33 Branch: Secondary pipeline that is connected to a main pipeline (see figure 2).

6.34 Loading: Static or dynamic load acting in the pipeline which shall be considered in the design.

6.35 Radial flow tee: A fitting with slots that allows the free passage of a pig.

6.36 High temperature: Operating temperature of the pipeline, higher than 90°C (194°F) and up to 150°C (302°F).

6.37 Deck piping: Pipe on the deck of the platform starting from the pig trap, or from the first cut-off valve on deck (see figure 2).

6.38 Pig trap (Launcher/Receiver): Equipment used for launching and receiving pigs (aee figure 2).

6.39 Transition length: Pipe section that connects the buried pipeline to the pipeline on the seabed (see figure 2).

7. SYMBOLS AND ABBREVIATIONS

AGA American Gas Association

API American Petroleum Institute

ASME American Society of Mechanical Engineers

ASTM American Society of Testing Materials

CSS Safety and Service Categories (Categorías de Seguridad y Servicio).

IEC International Electrotechnical Commission

ISO International Organization for Standardization

MBCPED Thousands of Heavy Oil Barrels Daily Equivalent (Miles de Barriles de Crudo




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Pesado Equivalente Diario).

NAD27 The North American Datum of 1927, information based on ellipsoid Clarke 1866

NMM Mean Sea Level

NRF Reference Standard

PEMEX Petróleos Mexicanos y Organismos Subsidiarios (Petróleos Mexicanos and Subsidiary Entities).

PEP Pemex Exploration and Production (Pemex Exploración y Producción).

SMTS Specified Minimum Ultimate Tensile Strength in N/mm2 (lb/pulg2 ).

SMYS Specified Minimum Yield Strength in N/mm2 (lb/pulg2 ).

σh Circumferential stress due to fluid pressure in N/mm2 (lb/in2)

σl Longitudinal stress in N/mm2 (lb/in2)

τ Shear Strength in N/mm2 (lb/in2)

° Degree

‘ Minutes

8. DEVELOPMENT

8.1 Subsea Pipelines Design

8.1.1 Design considerations

Subsea pipelines, except for pipeline branches, shall be designed so they can be inspected with smart pigs, selecting proper fittings for such purpose.

8.1.1.1 User basis. The user area within PEMEX that requests the design of a pipeline system for the transmission of hydrocarbons shall issue the user basis where the technical characteristics and quality parameters for the pipeline shall be indicated. The minimum information that this document shall contain is:

Work description.




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Project scope. Design service life. Locations (start and end). Arrangements for future interconnections. Operation conditions. Characteristics of the fluid to be transported. Volume to transport. Information about the pipeline route. Inspection and maintenance requirements. Instrumentation and safety devices. Reference standard NRF-001-PEMEX-2007 applicable for the pipe

specifications. Standards and specifications to be used in the project.

With this information, the designer shall prepare the design basis as per the following paragraph.

The designer shall request the geophysical and geotechnical surveys of the pipeline route to PEMEX.

8.1.1.2 Design basis: The minimum information that shall be included in the design basis and that the contractor shall prepare is the following:

Physical and chemicals characteristics of the fluid (information provided by the user).

Specifications of the material of the pipe and components. Pressure and temperature in normal and maximum operating conditions

(information submitted by the user). Loading conditions on the pipeline during its installation, operation and

maintenance (see 8.1.1.6). Additional thickness for corrosion. Operation philosophy. Protection systems to avoid internal and external corrosion of the pipeline. Geophysical and geotechnical information of the soil. Meteorological information (heights and heading of waves, speed and headings

of the current and design storm). Additional design requirements for the construction, operation and

maintenance. Standards and specifications to be used in the project.

8.1.1.3 Route selection: The route of the pipeline shall be selected taking into account the safety of personnel, the protection of the environment and the probability of damage of the




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pipeline and other facilities. For it selection, the following considerations shall be taken into account, as minimum:

Traffic of vessels. Fishing activity. Offshore facilities. Existing pipelines. Characteristics of the seabed (unsteady, irregular and others). Accidents, failures or potential hazards (geotechnical report). Seismic activity. Obstructions. Future development in the area and applicable installation methods. Ecologically-sensitive and protected areas.

8.1.1.4 Geophysical and geotechnical surveys: Once the pipeline route is defined, the contractor shall request, to PEMEX, the geophysical and geotechnical information of the corridor where the pipeline is intended to be constructed, which shall meet number 8.1 of NRF-229-PEMEX-2008.

8.1.1.5 Materials

8.1.1.5.1 Pipe: The pipe used in the design of subsea pipelines shall meet reference standard NRF-001-PEMEX-2007, for both sour and non-sour hydrocarbons service.

8.1.1.5.2 Fittings: Flanges, welded connections, studs, nuts, gaskets and other fittings used for hydrocarbon transmission pipelines shall meet the requirements for chemical composition, mechanical capacity, fabrication, component, and quality indicated in NRF-096-PEMEX-2004.

The valves that will be installed under the NMM shall meet the requirements of ISO 14723:2011. The valves that will be installed over the NMM shall comply with requirements of NRF-211-PEMEX-2008.

The use of misalignment flanges and flow tees is up to the designer’s discretion and their specifications and characteristics shall be as per the manufacturer’s catalogue and suitable for the service.

8.1.1.6 Loadings: All loads that may cause or contribute to a failure in the pipeline shall be identified and taken into account when designing the pipeline, considering at least the following:




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8.1.1.6.1 Pressure: Pipelines shall be designed to support a design internal pressure, which shall be equal to 1. 1 times the maximum operating pressure (Pom). The design shall consider the maximum possible positive differential between the design internal pressure and external pressure.

8.1.1.6.2 Live loads: They include the weight of the fluid being transported and any other external material like marine growth that is adhered to the pipeline.

8.1.1.6.3 Dead loads: Dead weights imposed to the pipeline shall be considered, which include the weight of the pipe itself, the components or fittings, coatings and concrete mattresses, if existing, and external pressure. Dead loads are very important where there are pipe sections without supports.

8.1.1.6.4 Dynamic loads: The design shall consider the dynamic loads and the stresses of them the pipe. These include impact and vibration due to the vortex produced by the current, swells, seism, and soil movement.

8.1.1.6.5 Pressure increase due to fluid expansion: The design shall take into account the increase of the pressure caused by the heating of the fluid transported.

8.1.1.6.6 Loads due to contraction and thermal expansion: The necessary measures shall be taken into account to consider the effects due to expansion and thermal contraction in the pipe systems.

8.1.1.6.7 Soil-pipe Interaction: In the design, the interaction between the soil of the seabed and the pipe shall be considered to determine the longitudinal displacement and deformation of the latter.

The soil-pipe interaction depends on the characteristics of the soil (shear strength and deformation properties), the pipeline (submerged weight, diameter and roughness of the surface) and loads.

8.1.1.7 Riser: The riser shall be installed in the external part of the platform and be supported on clamps (anchor and guiding), which shall be designed for the combination of critical loads. Installing pipelines in areas for wells and launch cradles shall be avoided. In case it is necessary the installation of two or more risers in the same leg, a relevant loading analysis shall be carried out. An insulating material shall be applied in the anchor and guiding clamps to avoid contact between the riser and the platform. The separation and design of the clamps shall be defined based on the structural analysis, considering: weight of the riser itself, pressure, temperature and strength produced by the swell and current, and a vortex analysis, both for the installation and operation phases.




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A protection system shall be installed to mitigate the temperature in the splash zone, which shall be extended to 4,00 m (13, 13 ft.) in the open air area and 3,00 m (9, 85 ft.) in the submerged area considering the NMM. The system might be from metallic and non-metallic material and it shall meet the requirements of Technical Specification P.2.0721.04-2008.

The joint between the riser and the expansion spool shall be designed as a simple connection, but that it guarantee the tightness and structural integrity under the specified load circumstances.

The riser shall be protected against vessel impacts (crew boat or supply vessels) with a structure (fender) fixed to the platform in the splash zone fabricated with ASTM A 36, API 5 L Grade B steel or equivalent.

8.1.1.8 Expansion Spool: The design of the expansion spool shall guarantee enough flexibility to absorb the loads in conditions produced during the operation and in conditions of storm in the platform. It may have a Z or L configuration. The expansion spool includes a straight pipe section superficial to the seabed of 30 meters after the last horizontal elbow, plus a transition length where the buried pipe starts until joining with the regular pipeline. This transition length shall be obtained through the allowable radius curvature for not exceeding the 18% of the SMYS. Besides, it shall be checked that it does not exceed the allowable combined stress.

Stiffeners elements shall be designed for the expansion spool when it is required by the structural analysis. The engineering drawing shall indicate, with a note, that these shall be removed once the expansion spool is installed and connected to the riser and the regular pipeline.

8.1.1.9 Connections, fittings, flanges and valves: All connections, accessories, flanges and valves shall have the same internal diameter as the pipe. Likewise, all the valves shall be full-bore.

In case that the internal diameters of the pipe and connection, fitting or valve to join are different, the design of the welded joint shall be done as per indicated in section 8.2.12.1 of NRF-030-PEMEX-2006. If the specified minimum yield stress of the fitting is different to the pipe, the welding material shall have mechanical properties, at least, equal to the element with higher strength.

The gaskets of the flanges shall resist the maximum pressure and the installation forces to which they are exposed.




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The contractor shall conduct a study of the pipeline operation philosophy to determine the need to install the sectioning valve in places required by the operating conditions and maintenance.

The valves that to be installed in the seabed shall be protected with a metallic structure fabricated in ASTM A 53 Grade B, API 5L Grade B steel or equivalent to avoid damages by the anchors.

SDV valves shall be installed in such way that the pipeline operates safely and that damages to the environment and the installations in case of emergency can be avoided. The valves shall be in easy access locations protected with a metallic structure fabricated in ASTM A 53 Grade B, API 5L, Grade B steel or equivalent, located preferably between the riser and the pig trap, or connection to the process pipeline.

8.1.1.10 Monitoring spool and transition piece: A monitoring spool shall be installed each kilometer to identify the location of the smart pig readings. Said spool consists of a pipe section with a fabricated joint at the middle of the same, which shall not have polyurethane filler or steel sheet, only the anti-corrosive coating in order to ease their localization.

The transition piece to join the regular pipeline with the pipeline in zone “B” shall have a minimum length equal to one diameter. The wall thickness of the piece shall be equal to the pipe with the greater wall thickness and have its ends beveled. The transition piece shall be used only when the wall thickness difference between the pipelines to join is greater than 2. 38 mm (3/32 in). The transition piece will be fabricated with the same specification of the pipe material.

8.1.1.11 Pig traps: The design, components of the package, and dimensions necessary for the pig launcher and receiver shall meet the requirements in NRF-178-PEMEX-2007.

8.1.1.12 Minimum separation between regular pipelines: The minimum distance that shall exist between two pipelines with parallel route is 20 m (65, 62 ft.).

8.1.1.13 Concrete coating: A hydrodynamic stability analysis shall be carried out as per the section 8.1.4 to determine the concrete coating thickness. Expansion spools shall have concrete coating up to the beginning of the vertical elbow up to the platform. The minimum thickness of the concrete coating is 25.4 mm (1in) with a maximum tolerance of +6, 35 mm (0.25 in) and the concrete characteristics shall meet the requirements stated in NRF-033-PEMEx-2003.

8.1.1.14 Burial of the pipeline: The contractor shall bury the pipeline in the seabed in such a way that it is 100% covered with filler material to protect it against the




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hydrodynamic strengths and external damages. The soil protection layer over the pipe shall be minimum 1,00m (3, 28 ft.).

The hydrodynamic stability shall be reviewed for the installation phase as per section 8.1.4. Only in those cases where the burial of the pipe is not possible; for example, a very short section, when near existing installations do not allow the burial, or as a result of the flexibility analysis, the pipeline is allowed to be installed superficially. Then, the hydrodynamic stability shall be verified for the operation phase as per section 8.1.4.

The pipelines arriving at the coast, in case there are not particular surveys of the site, shall be buried at a minimum of 3.00 m (9, 84 ft.) starting from water depths of 5.00 m (16, 4 ft.) towards the beach coast.

8.1.1.15 Marine growth: The effect of hard marine growth around the riser shall be taken into account for vortex and loads analysis in storm conditions, which shall be considered as the average of the measurements recorded in the last five inspections reports for different heights shall be considered, which also applies for new pipelines.

8.1.1.16 Subsea crossing: In a crossing of two pipelines, the minimum vertical separation from the top of one pipeline and the bottom of the other, considering the concrete coating, shall be 1.00 m (3,28 ft.). The angle between two pipeline crossings shall be as close as possible to 90°, not less than 30° preferably. Crossings in an expansion spool zone shall be avoided, in case it is not possible, restriction shall be avoided and the flexibility of the existing pipeline shall be revised.

Optionally, prior feasibility analysis, the level of burial depth of the existing pipeline shall be greater, in such way that it complies with the minimum separation between the top of one pipeline and the bottom of the other pipeline and meet the requirement of 1.00m (33m28 ft.) of burial depth for the new pipeline.

In the event there are limitations to lower the existing pipeline, the crossing may be executed by curvature radius or by the design of a bridge piece formed by elbows and straight sections in order to have the minimum separation of 1.00 (3,28 ft.) between the two pipelines. For bridge pieces, a bed of sand- cement sacks , or concrete coated mesh shall be placed to support both elbows (start and end of the bridge piece); also between the two pipelines and above the bridge piece in such a way that the fluid transported do not cause the pipeline to lift. A detailed hydraulic analysis shall be carried out to define the effect that this will have in the behavior of fluid. The elbows used in the bridge piece shall be of minimum 3 diameter radius so as to allow the run of the smart pig. For the curvature radius case, the final configuration of the pipeline shall not cause, under any circumstance, stress higher than 18% of the specified minimum yield stress. Besides, it shall be verified that it does not exceed the allowable combined stress.




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8.1.1.17 Free spans: The length of the free-spans shall be limited, both for the regular pipeline and the riser, in such way that the allowable circumferential and longitudinal stresses are met, as well as the buckling, vortex and fatigue criteria indicated in this document. For analysis purposes, the following shall be considered as minimum:

Supporting conditions (limits) in the ends. Interaction with adjacent free spans. Vibrations induced by the wind, swell and current. Pipeline tension. Erosion of soil adjacent to the pipeline. Depression of the seabed.

8.1.1.18 Vortices: The vorticity caused by the cross flow of the sea acting in a free section induces waves, both normal and perpendiculars to the flow vector, which may lead to the creation of large amplitude oscillations (resonance) if the vorticity frequency is close to the natural frequency of the free span vibration. The vorticity frequency shall be obtained through the following formula.

fv=StVD

1

Where:

fv Vortices frequency, Hz.St Strouhal Number= 0, 2V Velocity of flow perpendicular to the axis of the pipeline, m/sec (ft./s.).D Total outside diameter including the marine growth, m (ft.).

For the calculation of the flow velocity, the maximum wave height for Zone B and significant wave height for Zone A shall be considered. The vorticity shall be reviewed for return periods of 10 and 100 years.

The frequency of excitation caused by vorticity shall not be between the range 0, 8 Fn and 1, 2 Fn, being Fn the natural frequency of the pipeline, which shall be obtained from the following expression:

Fn=( CL span2 )( EIme )

1/2 2

Where:

C Constant that depends of the support conditions.




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¿ π /2 For simply supported sections and 3, 50 for restricted sections.

L span Span length, cm (in)

E Steel modulus of elasticity, kg/cm2 (lb/in2)

I Steel moment of inertia, cm4 (in4)

me Effective mass per unit length kg/cm (slug/ft.)

To determine the velocity ranges where oscillation can be produced by the vorticity, the following two parameters shall be used:

Vr= VFnD

3

Ks=2meδ

ρ D2

4

Where:

Vr Reduced velocity, m/s (ft./s)

Fn Natural frequency of the pipeline, Hz.

Ks Stability parameter.

δ Logarithmic decrement by structural damping.

ρ Water density, kg/m3 (lb/ft3).

The effective mass per unit length of pipeline is obtained through the following formula:

me=(W t+W r+W cm+W I+W c+CmW a ) /g 5

Where:

Wt Pipe weight, (kg/m) (lb/ft.).

Wr Weight of anti-corrosive coating, (kg/m) (lb/ft.).




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Wcm Weight of marine growth, (kg/m) (lb/ft.).

Wl Weight of concrete coating, (kg/m) (lb/ft.).

Wc Weight of content, (kg/m) (lb/ft.).

Wa Weight of water, (kg/m) (lb/ft.).

Cm Coefficient of added mass as per figure 3.

g Gravity, m/s2 (ft./s2)

8.1.1.18.1 Oscillations in parallel direction to the velocity vector: The vorticity can cause oscillations that make the pipeline to enter into resonance when Vr values exist between 1, 0 and 3, 5 and Ks ≤1, 8.

8.1.1.18.2Oscillations in perpendicular direction to the velocity vector: Perpendicular oscillations may occur perpendicular to the speed vector when Ks ≤ 16 and when Vr is in maximum and minimum values defined in figure 4.

In case of obtaining Vr and Ks values like in section 8.1.1.18.1 and 8.1.1.18.2, it shall be modified the separation of the clamps (riser) or reduced the free spans (subsea pipeline).

Figure 3. Values recommended for the added mass coefficient, Cm for pipeline.




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8.1.1.19 Fatigue: A fatigue analysis shall be carried out to the regular pipeline and riser depending on the length of the free spans subject to cyclic loads produced by vortex vibrations, hydrodynamic loads, and pressure and temperature cyclic variation, among others. In a general case, where stress variation is present due to the fluctuation of cyclic loads, the hypothesis of the linear damage or Miner´s rule can be used, which considers a stress histogram in function of the load amplitude. The design fatigue life calculated using this method shall be at least 10 times the service life. The fatigue criteria then is expressed as:

DFAT=∑i=1

s niN i

≤0.106

Where:

DFAT Cumulative fatigue damage.

n¡ Number of cycles held in i - th stress amplitude.

N¡ Number of cycles to the failure in i- th stress amplitude.

i Number of stress amplitude i=1…s.

Figure 4. Reduced velocity vs. Reynolds’s Number

8.1.1.20 Expansion and flexibility: All the stresses shall be checked for expansion and flexibility in critical zones like: riser, expansion spool, crossings, interconnections and




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others. For the flexibility analysis, the gradient temperature along the pipe shall be considered, taking into account the burial depth.

The equivalent stress shall be calculated using the following expression based on the combined Von Mises stress.

σ eq=√σ h2+σ I

2−σhσ I+3T2 7

Where:

σh Circumferential stress due to fluid pressure, in N/mm2 (lb/in2)

σ I Longitudinal stress, in N/mm2 (in2)

T Shear stress, in N/mm2 (lb/in2).

The maximum equivalent stress shall not exceed:

σ eq≤ f eq SMYS 8

Where feq is the design factor for equivalent stress.

feq = 1, 00 (Installation)

feq= 0, 90 (Operation)

SMYS = Specified Minimum Yield Strength in N/mm2 (lb/in2).

8.1.1.21 Branch connections: Subsea branches and manifold connections shall be designed as Zone A, forming part of the regular pipeline as per figure 2. This shall be always fabricated in Zone A, be superficial and have concrete mats depending on the the hydrodynamic stability study. To guarantee enough flexibility to absorb the movements caused by expansion, the installation of an expansion spool shall be considered, which shall be formed by long radius elbows.

The branch connections shall be done using flow tees. They shall meet reference standard NRF-096-PEMEX-2004 and have valves to guarantee the operation and safety conditions and cage protection.




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8.1.1.22 Hydraulic Analysis: A hydraulic analysis shall be carried out to guarantee that, under the operating critical circumstances, the pipeline keeps a proper mechanical-structural behavior during its service life.

8.1.1.23 Corrosion

8.1.1.23.1External corrosion: The piping and accessories that make up the subsea pipeline and that are submerged shall have systems that minimize the external corrosion, which shall have the following:

8.1.1.23.1.1 Anti-corrosive coating: The environment where the regular pipeline, expansion spool and riser, up to the splash zone are to be installed shall be considered when selecting the coating system, as well as the design service specified in the user basis.

For submerges zone, the anti-corrosive protection selected shall meet the requirements of NRF-026-PEMEX-2008.

For the open air zone between the splash zone and the pig traps, the anti-corrosive coating shall met the requirements of NRF-053-PEMEX-2006.

8.1.1.23.1.2 Cathodic protection: All subsea pipelines shall have a cathodic protection system to protect the system against corrosive effects caused by an anti-corrosive failure during its application, or during installation and operation of the pipeline. The design and installation of the cathodic protection systems shall be executed as per NRF -047-PEMEX-2007. The cathodic protection shall be applied using galvanized aluminum anodes and designed for the whole service life of the pipeline.

To guarantee the efficiency of the cathodic protection of the subsea pipelines, the following criteria shall be complied:

a) A potential pipe/soil protection (cathodic) minimum of -800 millivolts, measured in regard to a silver/silver chloride (Ag/AgCI) reference electrode. for surface pipelines on the seabed.

b) A potential pipe/soil protection (cathodic) of -900 millivolts, when the surrounding area of the pipeline is in anaerobic conditions and sulfate-reducing bacteria exist (buried pipelines).

The subsea systems that are connected with other existing pipelines shall have a compatible cathodic protection system.

For concrete coated pipeline, the anode thickness shall be equal or less than the concrete coating thickness. Anodes shall be bracelet type and welded for continuous electricity with




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the pipeline. For pipeline without concrete coating, the anode shall be protected properly in the ends to avoid damages during the laying.

At least one sacrificial anode shall be installed in the expansion spool, and another in the riser; however, the total amount shall be defined by the design of the protection system.

An insulating joint shall be installed above the anchor clamp in the open air area to aisle electrically the subsea pipeline from the platform structure or the land facilities; this, in compliance with numbers 8.2.1.2 and 8.2.1.6 of NRF-047-PEMEX-2007 and number 8.6 of NRF-096-PEMEX-2004.

8.1.1.23.2 Internal corrosion: Subsea pipelines for transmission of liquid or gas hydrocarbons and other services that contain aggressive or corrosive agents shall have internal protection systems based on corrosion inhibitors, as well as the equipment and devices to be fitted in the pipeline. The systems based on corrosion inhibitors shall comply with the requirements stated in NRF-005-PEMEX-2000.

8.1.2 Subsea pipeline classificationIt has been established three Safety and Service Categories (CSS) for the design of a pipeline according to the fluid type, the zoning and the volume of the product transported. In order to choose the proper design factor, which includes the risk conditions of the pipeline, said categories are: Very high, High and Moderate.

The zoning of the pipeline is defined as follows (See figure 2):

Zone A. It involves the regular pipeline and branches. Zone B. It involves the riser and expansion spool.

Regarding the type of fluid transmitted, two groups shall be considered:

Gas Flammable and/or toxic gases besides hydrocarbon mixtures (oil and gas pipeline).

Liquid Flammable and/or toxic liquids.

The categorization of a specific pipeline transmitting gas, or oil and gas mixture shall be obtained by estimating a volume in Thousands of Heavy Oil Barrels Daily Equivalent (MBCPED) as per Annex B. This categorization may be raised to a higher category based on a risk quantitative estimate and failure consequences.

8.1.2.1 Pipelines transmitting flammable and/or toxic gases: The CSS for subsea pipelines transmitting flammable and/or toxic gases shall be selected as per table 1.

PRODUCTION NUMBER ZONE A ZONE B

0-300 MBCPED HIGH VERY HIGH




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Table 1. Safety and Service Categories for subsea pipelines transmitting flammable and/or toxic gases.

8.1.2.2 Pipelines transmitting flammable and/or toxic liquid: The CSS for subsea pipelines transmitting flammable liquids shall be selected as per table 2.

PRODUCTION LEVEL ZONE A ZONE B

0-100 MBCPED MODERATE MODERATE

101-1000 MBCPED VERY HIGH HIGH

Table 2. Safety and Services Categories for subsea pipelines transmitting flammable and/or toxic liquids.

8.1.2.3 Pipelines transmitting non-flammable or non-toxic fluids: The pipelines transmitting non- flammable or non-toxic fluids (water, nitrogen and others) shall be categorized as Moderate.

8.1.3 Mechanical effects

8.1.3.1 Internal Pressure: The pipeline and its components shall be designed to resist the design internal pressure (Pint) and the external pressure (Pext) due to the hydrostatic load, which shall not be less than the internal pressure at any point of the pipeline in a static condition.

The thickness required for the internal pressure in the design of subsea pipelines transmitting liquid or gas, is obtained by the following formula:

t=P iD

2SMTS F pb f t+Pi

9

Where:

Zone A

Pi=P∫¿−Pext ¿10




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Zone B

Pi=P∫¿¿11

Pi Internal pressure, in N/mm2 (lb/in2).

Pint Design internal pressure, in N/mm2 (lb/in2).

Pext Hydrostatic external pressure acting in the pipeline, in N/mm2 (lb/in2) .

D Nominal outside diameter of the pipeline, in mm (in).

t Steel wall thickness of the pipe for internal pressure, in mm (in).

SMTS Specified Minimum Ultimate Tensile Strength, in N/mm2 (lb/in2).

FPb Design factor for internal pressure indicated in Table 3.

Ft Temperature factor indicated in Table 4.

Content

ZONE A ZONE B

MODERATE HIGH VERY HIGH MODERATE HIGH VERY HIGH

Gas N/A 0,60 N/A N/A N/A 0,44

Oil 0,63 N/A 0,57 0,52 0,47 N/A

Table 3. Internal pressure design factors (Fpb)

TEMPERATURETEMPERATURE FACTOR

°C °F Ft

121 or less 250 or less 1,000

130 266 0,989

140 284 0,977

150 302 0,966

Note: Intermediate temperatures shall be interpolated.

Table 4. Temperature factor (ft.) for steel pipes




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8.1.3.1.1 Required minimum thickness: The minimum thickness required to support the stress produced by internal pressure is determined through the following formula:

t r=t+t c 12

Where:

tr Minimum thickness required by Internal pressure, in mm (in)

t Design thickness for internal pressure (See 8.1.3.1.1.), in mm (in)

tc Corrosion Tolerance (See 8.1.3.1.1.2), in mm (in)

For the design of subsea pipelines, the commercial thickness shall be selected starting from the minimum required thickness (tr). The percentage of fabrication tolerance shall be subtracted from this commercial thickness (See 8.1.3.1.1.3); this difference shall be higher or equal to the minimum required. On the contrary, the greater following that is fabricated shall be selected.

tr ≤ t com−t fab 13

Where:

Tcom Commercial thickness for internal pressure, in mm (in.)

Tfab Fabrication tolerance (See 8.1.3.1.1.3), in mm (in.)

8.1.3.1.1.1 Design thickness: The design thickness for internal pressure (t) is calculated using the formulas 9 to 11.

8.1.3.1.1.2 Corrosion tolerance: A corrosion range shall be used based on the statistical results of handling of product that will be transported. This information that shall be provided by PEMEX. If this information is not available, an additional weight of 0,159 mm (6, 25 mil) per year for regular pipeline (Zone A) and 0,254 mm (10 mil) per year for riser (Zone B) shall be used.

Additionally, the study and design of the respective cathodic protection system shall be considered as well as the anti-corrosive protection systems with coatings for submerged and open air zones; likewise, the internal anti-corrosive protection using corrosion inhibitors when the handled fluid requires it, based on operating conditions and statistical results of similar systems and on the possible integration with other installations.

8.1.3.1.1.3 Fabrication tolerance: The fabrication tolerance thickness shall be obtained regarding the tolerance percentage value shown in Table 5.




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OUTSIDE DIAMETER MM (IN.) AND PIPE TYPE

PERCENTAGE OF TOLERANCE

(%) GRADE X42 OR HIGHER

73,0 (2,875) and less, seam or seamless 12,5

Higher than 73,0 (2,875) but less than 508,0 (20), seam or seamless

12,5

508,0,(20) and higher, seam 8,0

508,0 (20) and higher, seamless 10,0

Table 5. Percentage of the fabrication tolerance in the wall thickness

8.1.3.1.1.4 Thickness for high temperature in fixed restricted pipelines: The thickness of the pipe shall be enough to bear the stress created by thermal loads. The thickness calculation by this effect for restricted pipelines (regular pipeline) shall be as per the following formula:

t t=0,7¿¿ 14

Where:

Tt Pipe steel wall thickness due to internal pressure, in mm (in)

Pint Design internal pressure, in N/mm2 (lb/in2)

Pext Hydrostatic external pressure acting on the pipeline, in N/mm2 (lb/in2)

D Nominal outside diameter of the pipe (in)

SMYS Specified Minimum Yield Strength in N/mm2 (lb/in2)

Ft Temperature factor indicated in Table 4.

E Modulus of elasticity of the pipe steel indicated in Table 6 in N/mm2 (lb/in2)

α Thermic expansion coefficient in mm/mm/°C (in/in/°F)

T1 Installation temperature in °C (°F); Unless there is a measured or statistical value for the bottom temperature, this shall be 15° C.

T2 Design temperature in °C (°F).

TEMPERATURE MODULUS OF ELASTICITY




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°C °F lb/in2 x 106

21 70 29,5

90 194 28,8

110 230 28,6

130 266 28,5

150 302 28,3

Note: Intermediate temperatures shall be interpolated.

The commercial thickness shall be selected as the immediate above to the calculated for temperature. The fabrication tolerance percentage shall be subtracted from this commercial thickness (see 8.1.3.1.1.3); this difference shall be equal or higher than the required temperature thickness. On the contrary, the immediate above fabricated shall be selected.

The commercial thickness selected for the regular pipeline shall be the greater between the required for high temperature, in accordance to this paragraph, and the required for internal pressure, as per 8.1.3.1.

In case the commercial thickness selected for the regular pipeline is greater than the commercial thickness selected for the riser and the expansion spool, the thickness for these two elements shall be equal to the regular pipeline.

The temperature thickness calculated for restricted straight sections shall not be less than the value 20 in the D/t ratio. Otherwise, the material grade can be increased taking into account the limitations indicated in NRF-001-PEMEX-2007, or the superficial installation of the pipeline can be considered with a configuration based on induced horizontal curvatures. In such case, the hydrodynamic stability shall be checked for the operating condition as per 8.1.4.

8.1.3.2 Revision of thickness for other conditions: The required wall thickness for internal pressure or temperature shall be suitable to support other possible effects resulting from stress loads to which the riser may be subject during the installation or operation including expansion and flexibility. The following shall be considered:

a) Installation: t=t com−t fab 15




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b) Operation: t¿ t com−t fab−t c 16

Where:

t Thickness used for the review of ther effects, in mm (in)

t com Commercial thickness obtained for internal pressure, in mm (in)

t fab Fabrication tolerance (See 8.1.3.1.1.3), in mm( in)

tc Corrosion tolerance (See 8.1.3.1.1.2), in mm (in)

8.1.3.2.1 Longitudinal tension (Tu): In order to consider this effect, the longitudinal stresses in the installation or operation phase shall be taken into account. The capacity of the pipeline is given by the following expression:

Tu=1,1SMYS As 17

Where:

Tu Ultimate longitudinal tension, in N (lb)

SMYS Specified Minimum Yield Stress, in N/mm2 (lb/in2)

As Nominal area of the steel pipe cross section, in mm2 (in2)

The allowable capacity of longitudinal tension (tcp) shall be calculated using any of the following expressions, depending on the design phases:

T cp=0,62T (Installation Phase) 18

T cp=0,56T (Operation Phase) 19

Where: T cp in N (lb)

8.1.3.2.2 External pressure: During the installation and operation phases, subsea pipelines are subject to external pressure conditions. The pressure differential regarding the internal pressure acting on the pipeline may cause a collapse of the pipeline. A review




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of the collapse pressure effects and buckling propagation shall be done to guarantee an adequate strength of the pipeline taking into account the variations of the geometric properties, ovality, stresses and external pressures (P ext).

8.1.3.2.2.1 Collapse pressure (Pc): The capacity at net collapse pressure (Pc) shall be calculated using the expression:

( Pc

Pe

−1)[( Pc

P y)2

−1]=( Pc

P y) f o( Dt )

20

Where:

Pc Collapse pressure, in N/mm2 (lb/in2)

Py Collapse fluency pressure = 2t (SMYS)

D

21

Pe Collapse elastic pressure: 2E1−v2 ( tD )

3 22

Fo Ovality factor =Dmax−Dmin

Dmax+Dmin

23

SMYS Specified Minimum Yield Strength, in N/mm2 (lb/in2).

E Elastic module of the steel pipe, in N/mm2 (lb/in2).

v Poisson’s ratio= 0,30 for steel.

D Nominal diameter of the pipe, in mm (in).

D max Maximum diameter of the cross-section of the pipe, in mm (in).

D min Minimal diameter of the cross-section of the pipe, in mm (in).

t Pipe wall thickness as per number 8.1.3.2, in mm (in).




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Allowable capacity of the pipe subject to external pressure shall be calculated with the expression:

PCDE=¿0,70P c¿24

Where:

P CDE Allowable capacity of collapse pressure in the subsea pipeline, in N/mm2 (lb/in2).

Allowable collapse pressure calculated with the expression 24, shall guarantee that:

PCDE>Pext−P∫¿ ¿25

8.1.3.2.2.2 Buckling propagation (Pp): The buckling propagation in pipelines shall be calculated using the following expression:

Pp

SMYS=34 ( tD )

2,5 26

Where:

Pp Propagation pressure, in N/mm2 (lb/in2).


t Pipe wall thickness calculated as per 8.1.3.2, in mm (in).


The allowable capacity of the pipe before the buckling propagation effect shall be calculated with the expression:

Ppc =0, 73Pp 27

where:




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Ppc Propagation pressure allowable capacity, in N/mm2 (lb/in2).

The allowable propagation pressure calculated with the expression 27 shall guarantee that:

Ppc>Pext−P∫¿ ¿28

For the external pressure calculation, the maximum wave height shall be considered for a return period of 10 years for the installation condition. For the operation condition, a review of the propagation pressure i shall be performed considering the storm wave height for a return period of 100 years.

8.1.3.2.3 Bending moment (Mu): In order to consider this effect, the sum of all bending stresses that are presented in the installation or operation phase shall be taken into account. The cross-section bending capacity is given by the following expressions:

Mu=1,1[SMYS D2t (1−0,001 Dt )] 29

Where:

Mu Ultimate cross-section bending moment for design, in N. mm (lb/in).

SMYS Specified Minimum Yield Strength), in N/mm2 (lb/in2).


t Pipe wall thickness calculated as per 8.1.3.2 in mm (in).

The permissible capacity that the pipe will have shall be calculated by the following expression:

Muc=f MMU 30

Where:

Muc Allowable bending moment capacity, in N. mm (lb.in).

fM Design factor for cross-section bending indicated in Table 7.




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ZONE OPERATION INSTALLATION

A 0,57 0,67

B 0,53

Table 7. Design factor by Bending Moment (fM).

8.1.3.2.4 Global buckling (Cg): Global buckling in straight sections subject to pure compression strengths that may exist in free spans and crossing shall be reviewed.

The global buckling capacity shall be calculated using the following expression:

Cg=1,1 [SMYS (1,2.−0,25 λ2 ) ] As 31

Where:

Cg Compression load by global buckling, in N (lb).


λ Slenderness ratio = KLr ( SMYS

E )0,5 32

K Effective length factor that depends on the support conditions in the section ends.

For fitted ends K=0, 5 and articulated ends K=1,0.

L Section length, mm (in).

R Radius of gyration = √ IAs

33

I Moment of inertia of the pipe steel section, in nm4 (pul4

As Cross-section area of steel pipe, in mm2 (in2).

E Elasticity modulus of pipe steel, in N/mm2 (lb/in2).

The allowable capacity that the pipe will have shall be calculated with the expression:

Cgp=0,54Cg 34

Where:

Cg p Global buckling allowable capacity for design, in N (lb).




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For pipelines cases in superficial or buried straight sections, the calculation of the global buckling capacity shall take into account the effect of the lateral and/or vertical restriction of the soil.

8.1.3.2.5 Formulation of design for combined load status: During the pipe lay or installation phase, the requirements indicated next shall be followed for the load combination effects.

8.1.3.2.5.1 Tension and bending moment (Tu-Mu): The capacity of the pipeline to support the combined strengths of Tension and Bending Moment shall be verified through the following expression:

[( MMu )

2

+( TTu )2]0,5

≤ f TM35

Where:

F TM Design factor for combination of Tension and Bending Moment = 0,54.

Mu Cross-section bending ultimate moment, in N.mm (lb.in) (Eq.29).

Tu Ultimate longitudinal tension, in N( lb) (Eq. 17).

M Applied bending moment, in N.mm (lb.in).

T Applied axial load, in N (lb)

8.1.3.2.5.2 Axial load, bending moment and collapse pressure (Tu, Mu-Pc): The pipeline capacity to support the combined stresses Axial Load, Bending Moment and Collapse Pressure shall be verified using the following expression:

[( MMu )

2

+( PPc )

2

+( TTu )2]0,5

≤ f TMPc

36

Where:

P External acting pressure, in N/mm2 (lb/in2).

Pc Collapse pressure, in N/mm2 (lb/in2). (Eq.20).

M Applied bending moment, in N.mm (lb.in).

Mu Design ultimate cross-section bending moment, in N.mm (lb.in). (Eq.29).

T Applied axial load, in N(lb).




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Tu Ultimate longitudinal tension, in N (lb) (Eq.17).

F TMPc Design factor for combination of tension, bending moment and collapse pressure =0,80.

8.1.4 Hydrodynamic stability

A hydrodynamic stability analysis shall be carried out to verify that the horizontal stability factors of the pipeline comply with what it is indicated in this section. This analysis shall be carried out for installation and operation conditions of the pipeline, using the levels 2 and/or 3 of the program AGA “Analysis for Subsea Pipeline on-Bottom Stability”. It shall be considered the vertical and horizontal forces acting simultaneously, as well as the direction of the swell and current. The weight of the submerged pipeline can be controlled by the combination of thickness and density of the concrete coating.

The analysis for the installation condition shall be carried out with the regular pipeline exposed, empty and for a 10 years storm period. The design parameters for this condition are indicated in Table 8.

For the operation condition, the hydrodynamic stability analysis shall be carried out only if the regular pipeline, or a section of this, is not buried for any of the reasons indicated in 8.1.1.14. The analysis of this phase shall be carried out with the pipeline exposed, filled with fluid and for a 100 year storm period. The design parameters considered for the operation phase are indicted in Table 9.

a) A sea bottom velocity (U1/100), for a 4 hour period of storm development.b) A sea bottom velocity (U 1/1,000), for a 3 hour period of storm completely developed.

The two stability factors calculated for the two sea bottom velocities shall be equal or higher than the stability factor indicated in Tables 8 and 9, as the case may be.

The oceanographic parameters that shall be considered in the analysis are indicated in sections 8.1.4.2 for return periods of 10 years; and 8.1.4.3, for a return period of 100 years.

It shall be checked that the pipelines are vertically stable in the empty condition (installation), for which it shall be verified that the submerged weight of the pipeline is 1.10 times the rising force , as minimum for conditions a) and b) mentioned above.

The buried condition of the pipelines shall be reviewed regarding sinking and buoyancy. Both, for gas and liquid pipelines, sinking shall be evaluated assuming that the pipeline is filled with water, and buoyancy shall be evaluated assuming that the pipeline is empty.




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If the specific submerged weight of the pipeline filled with water is less than the submerged soil, any other analysis for sinking is not required. If according to the characteristics of the soil liquation may be present, it shall be checked that the sinking depth of the pipeline does no produce stresses higher than 18% of the MYS as a consequence of the curve.

If the specific submerged weight of the pipeline empty is less than the submerged soil, then the shear strength of the soil shall be reviewed as to indicate it is appropriate to avoid buoyancy.

If the stability of the pipeline cannot be guaranteed with the concrete coating and the burial, using an anchor system, concrete mesh or path modification of the pipeline shall be considered as an option.

DESIGN PARAMETERS INSTALLATION PHASE

Initial burial of the pipeline. Superficial to seabed (1).

Horizontal stability factor. FE= 1,1

Consideration of the fluid weight. Empty pipe.

Soil characteristics.To take data of the corridor geotechnical survey carried out with static and dynamic tests, as per section 8.1.1.4.

Significant wave height. Annex A (2) data corresponding to a return period of 10 years.

Current velocity at 95% of depth. Annex A (2) data corresponding to a return period of 10 years.




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Wave peak period for Bay of Campeche and Litoral Tabasco.

11,3 s.

Wave peak period for the North Zone and Lankahuasa.

11,9 s.

Minimum specific gravity 1,2

(1) A different burial depth from the superficial depth may be proposed depending on the analysis of instantaneous settlement caused by the pipeline installation activities.

(2) The direction of the swell and the current shall be taken into account as per section 8.1.4.2.2.

Table 8. Design parameters for horizontal hydrodynamic stability of subsea pipelines in the installation phase

DESIGN PARAMETERS OPERATION PHASE

Pipeline burial Superficial to seabed (1).

Horizontal stability factor

CSS FE gas FE oil

MODERATE ---- 1,1

HIGH 1,0 ----

VERY HIGH --- 1,3

Fluid weight consideration Filled pipe

Soil characteristics Obtaining data of the corridor geotechnical survey carried out with static and dynamic tests, as per

section 8.1.1.4

Significant wave height Annex A (2) data corresponding to a return period of




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100 years.

Current velocity at 95% of depth Annex A(2) data corresponding to a return period of 100 years.

Wave peak period for the Bay of Campeche and Litoral Tabasco

13,0 s.

Wave peak period for North Zone and Lankahuasa 12,3 sec.

(1) A burial depth different from the superficial depth may be obtained depending on the analysis of instantaneous settlement caused by the pipeline installation activities.

(2) The direction of the swell and the current shall be taken into account as per the section 8.1.4.2.2.

Table 9. Horizontal hydrodynamic stability design parameters of subsea pipelines in operation phase

8.1.4.1 Buoyancy analysis of buried pipeline: When the pipeline is buried it tends to float or sink in storm conditions. This phenomenon depends on the pipeline weight (including the content), density of the seabed and its strength to shear stress.

The buoyancy revision of the buried pipelines shall be carried out of as follows:

1) Soil strength plus the additional strength for the soil weight over the pipeline.

R s=( 2C s

Dt )+(⋎s Dt H c

A t) 37

Where:

Rs Soil resistance strength to sinking or buoyancy per volume unit of the pipeline, in lb/ft3.

Cs Shear stress strength of non-drained soil, in N/m2 (lb/in2).

Dt Total pipeline outside diameter including concrete coating in m (ft.).

⋎s Submerged weight of seabed in N/m3 (lb/ft3).

Hc Seabed thickness above the pipeline in m (ft.).

At Cross-sectional area of the pipeline, including concrete coating in m2 (ft2).




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2) Buoyancy force. F=W s−W a

A t

38

Where:

F Buoyancy force, in N/m3 (lb/ft3).

Ws Dry weight of the pipeline per length unit, in N/m (lb/ft.). It includes the sum of the weights of the pipeline, content, concrete coating and anti-corrosive coating.

Wa Weight of the water drained by the pipeline, in N/m (lb/ft.).

At Cross-section of the pipeline in m2 (ft2), it includes the concrete coating thickness.

The following inequality shall be complied:

F<Rs 39

The previous review shall be done considering the shear resistance of the remodeled soil (reduced).

8.1.4.2 Oceanographic parameters for return period of 10 years

8.1.4.2.1 Wave height and current velocity: Wave heights and current velocities for different zones in the Gulf of Mexico for a return period of 10 years are indicated in figures A-1 to A-4 of Annex A.

8.1.4.2.2 Swell and current direction: For the hydrodynamic stability analysis, the incidence angle of the swell and the current with the subsea pipeline shall be taken into account.




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8.1.4.2.2.1 Bay of Campeche and Litoral Tabasco: Heading of the swells shall be considered along with the most probable wave direction. A heading of S 11° 15’ E, while the current velocity is parallel to the bathymetry (See figure 5). The bathymetry is considered uniform and regular.

Figure 5. Direction of swells and current for the 10 and 100 year return period in Bay of Campeche and Litoral Tabasco.

8.1.4.2.2.2 North Zone and Lankahuasa: The heading of the swell shall be considered along with the most probable wave direction. A heading of 33° 45’ E, while the direction of the current velocity is parallel to the bathymetry (See figure 6). The bathymetry is considered uniform and regular.

Figure 6. Direction of swells and current for a 10 year return period in the North Zone and Lankahuasa




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8.1.4.3 Oceanographic parameters for a return period of 100 years

8.1.4.3.1 Wave height and current velocity: The height of the waves and current velocities for the different zones in the Gulf of Mexico for a return period of 100 years are indicated in figures A-5 to A-8 of Annex A.

8.1.4.3.2 Direction of the swell and current

8.1.4.3.2.1 Bay of Campeche and Litoral Tabasco: The heading of the swell shall be considered with the most probable wave direction. A heading of S 11° 15’ E, while the speed direction is parallel to the bathymetry (See figure 5). The barometry is considered uniform and regular.

8.1.4.3.2.2 North Zone and Lankahuasa: The heading of the swell shall be considered with the most probable wave direction. A heading of S 78° 45’ W, while the current velocity direction is parallel to the bathymetry (See figure 7). The barometry is considered uniform and regular.

Figure 7. Direction of the swell and current for a return period of 100 years in North Zone and Lankahuasa

8.1.5 Design deliverable documentation

As minimum, three sets of copies shall be submitted at the end of the design project, both in print and electronic version (AutoCAD and Window environment) to the requesting Pemex area, as minimum the following:

Design bases:




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Basic information that involves all the aspects considered in the design: Calculation reports.

o Determination of thickness for internal pressure, high temperature and

review for other effects. o Flexibility analysis (riser, free span, crossings, interconnections, among

others).o Vortices analysis.

o Hydrodynamic stability analysis.

o Cathodic protection.

o Riser clamps design.

Flowcharts. Particular specification sheets. Project drawings (when the operating conditions are higher than 90°C, a note shall

be attached to each drawing indicating the following: after the pipeline construction is finished, a detailed geophysical survey shall be carried out, which provides the profile of the pipeline along the corridor as to detect free spans and irregularities for relevant stress analysis and avoid of upheaval or lateral buckling problems).

Isometrics Work volume. Requisitions.

In addition, the user or PEMEX shall specify the technical basis of the bidding, the documentation and additional scope of the deliverable documentation and information.

9. RESPONSIBILITIES

9.1 Petróleos Mexicanos and subsidiary entities

9.1.1 Submitting the information required by this reference Standard to the design services provider for the development of the hired activities.

9.1.2 Granting the necessary document approvals before, during and at the end of the activities required by this reference Standard.

9.1.3 Carrying out or ensuring that the verification of compliance with the requirements of the reference Standard is carried out in a documented manner.




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9.2 Pemex Exploration and Production Technical Standardization Sub-Committee

Receiving, analyzing and attending comments and improving suggestions to the requirements established in this standard to keep its content and requirements updated; with the purpose to make sure that the operations carried out for the design of the subsea pipeline are executed in a precise, reliable and safe way.

9.3 Contractors

9.3.1 The contractor of the design services for subsea pipelines shall demonstrate that the company is experienced in the development of designs for similar project.

9.3.2 If applicable, it shall prove that it has qualified or specialist personnel available in the design of subsea pipelines area.

9.3.3 The contractor shall have sufficient equipment, instrumentation and appropriate infrastructure available for executing the activities and obligations required by this standard.

9.3.4 The contractor shall provide, to PEMEX representative, access to the facilities and information related with the activities required by this NRF during the validity of the contract.

10.CONCORDANCE WITH MEXICAN OR INTERNATIONAL STANDARDS

This standard is not in concordance with any Mexican or international standard.

11.BIBLIOGRAPHY

This standard is based on the technical bibliographic references indicated below:

ISO 13623:2000 Petroleum and natural gas industries-pipeline transportation systems, First edition, April 2000.

American Gas Association (AGA)

Submarine Pipeline on –bottom stability, 1993




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API SPEC. 5L /ISO 3183 Specification for Line Pipe. Forty-Fourth Edition, October 2007.

API RP 1111-1999 Recommended Practice for Design, Construction Operation and Maintenance of Offshore Hydrocarbon Pipelines “Limit State Design”. Third edition, July 1999.

API RP 1111-1993 Recommended Practice for Design, Construction, Operation and Maintenance of Offshore Hydrocarbon Pipelines. Second edition, November/1993.

ASME B31.G. Manual for Determining the Remaining Strength of Corroded Pipelines, 1991.

ASME B31. 4-2006 Pipeline Transportation Systems for Liquid Hydrocarbons and other Liquids.

ASME B31. 8-2207 Gas Transmission and Distribution Piping Systems.

ASTM A 36/1 36M-05 Standard Specification for Carbon Structural Steel, 2005.

ASTM A 53/A 53M-06a Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc –Coated, Welded and Seamless, 2006.




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Bea Robert Risk based criteria for Design and Requalification of Pipelines and Risers in the Bay of Campeche.

Det Norske Veritas (DNV) (Rules for Submarine Pipeline Systems, 1981/ 1996).

OFFSHORE STANDARD DNV-OS-F101

Submarine Pipeline Systems, October 2007.

Diavaz, S.A. de C.V. Inspecciones a ductos ascendentes en 1996, para Pemex Exploración y Producción.

(Riser Inspections, 1996 for Pemex Exploration and Production).

IMP Obtención de factores de diseño por esfuerzos permisibles (f) para los posibles efectos actuantes en líneas submarinas (Fases de Operación e Instalación).Proyecto F-00926, febrero de 2001.

(Obtaining allowable stresses design factors (f) for the possible effects acting on the subsea pipelines (operation and installation phases)). Project F-00926, February 2001.

IMP “Evaluación a ductos ascendentes y líneas submarinas del Activo Cantarell”. Proyecto FA-4934, enero de 1997.

(“Evaluation of risers and subsea pipelines of Cantarell Oil Field”. Project FA-4934, January 1997).

IMP “Análisis de riesgo para líneas submarinas superficiales”.

Proyecto FA-2325, marzo de 1991.

(“Risk analysis for shallow subsea pipelines”).

Project FA-2325, March 1991.

“Información metaoceánica para el diseño de líneas submarinas en la Sonda de Campeche”. Octubre de

(“MetaOcean information for the design of subsea pipelines in Campeche




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1997. Bay”. October 1997).

Oceanweather Update of Meteorological and Oceanographic Hindcast Data and Normal and Extremes, Bay of Campeche). Oceanweather, November / 1996.

Oceanweather Update of MetaOcean Design Data for Zone North and Bay of Campeche, Oceanweather, July / 2006.

Especificación Técnica

P.2.0721.04-2009

Sistemas de protección del ducto ascendente en la zona de mareas y oleaje para temperatura alta.

(Riser protection system in splash and wave zone for high temperatures”.




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12. ANNEX

Annex A. Oceanographic information for the Gulf of Mexico.

Figure A-1. Velocities of current on the surface at 50% and 95% depth for Bay of Campeche and Litoral Tabasco (Return period of 10 years)




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Figure A-2. Velocities of current on the surface at 50% and 95% depth for North Zone and Lankahuasa (Return period of 10 years)




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Figure A-3. Maximum and significant wave height for Bay of Campeche and Litoral Tabasco (Return period for 10 years)

Note: Only applicable for hydrodynamic stability.




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Figure A-4. Maximum and significant wave height for North Zone and Lankahuasa (Return Period of 10 years)

Note: Only applicable for hydrodynamic stability.




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Figure A-5. Velocities of current on the surface at 50% and 95% depth for Bay of Campeche and Litoral Tabasco (Return period of 100 years)




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Figure A-6 (Velocities of current on the surface at 50 and 95% depth for north Zone and Lankahuasa (Return period of 100 years)




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Figure A-7. Maximum and significant wave height of Bay of Campeche and Litoral Tabasco (Return period of 100 years)

NOTE: Only applicable for hydrodynamic stability.




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Figure A-8. Maximum and significant wave height for North Zone and Lankahuasa (Return period of 100 years)

NOTE: Only applicable for hydrodynamic stability.




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Annex B. Conversion of the gas and light oil production in Thousands of Heavy Oil

Barrels Daily Equivalent.

1) The production of the gas pipelines shall be converted into Thousands of Heavy Oil Barrels Daily Equivalent using the following formula:

1 MBCPED= 139,798 m3 (4, 937 million cubic feet) of gas per day.

2) The production of the light oil pipelines shall be convert into Thousands of Heavy Oil Barrels Daily Equivalent using the following formula:

1 MBCPED = 140,83m3 (140, 83 m2) 0,886 thousands of barrels) of light oil per day.

Documents

Nrf 013 Pemex 2009 English