Offshore Pipeline Design
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Offshore Pipeline Design MP 20-P-01 June 1998
Scope This Mobil Engineering Practice (MEP) covers basic requirements for the design of offshore pipelines, pipeline risers, risers in J-tubes and pipelines routed across platforms. This MEP and additional requirements in MP 65-P-06 cover the basic design of flowlines and flowline risers. Onshore sections of pipeline that are a continuation of an offshore pipeline may also be included. Process piping and related facilities (design specified by MP 16-P-01), arctic environments, flexible pipe, thermal insulation and emergency shutdown valves are not within the scope of this document. Line pipe materials, weight coating, corrosion protection and installation requirements are covered under other MEPS.
Version 0
MP 20-P-01
Offshore Pipeline Design
June 1998
Table of Contents Scope................................................................................................................................... 1 1.
References.................................................................................................................... 5 1.1.
MEPS–Mobil Engineering Practices.................................................................... 5
1.2.
Mobil Data Sheets ............................................................................................... 5
1.3.
Mobil Tutorials ..................................................................................................... 6
1.4.
AGA–American Gas Association......................................................................... 6
1.5.
API–American Petroleum Institute....................................................................... 6
1.6.
ASME–American Society of Mechanical Engineers ............................................ 7
1.7.
CFR–U.S. Code of Federal Regulations ............................................................. 7
1.8.
DnV–Det norske Veritas ...................................................................................... 7
1.9.
MMS–Minerals Management Service, U.S. Department of the Interior ............... 7
1.10. NACE–National Association of Corrosion Engineers .......................................... 7 2.
3.
4.
General.......................................................................................................................... 8 2.1.
Transitions........................................................................................................... 8
2.2.
Design Parameters.............................................................................................. 8
Pipeline Route Selection ............................................................................................. 9 3.1.
Investigation of Route Alternatives ...................................................................... 9
3.2.
Hazard/Archaeological Survey .......................................................................... 10
3.3.
Engineering Study of the Selected Route.......................................................... 11
3.4.
Defining Parameters.......................................................................................... 11
Pipeline Diameter Selection ...................................................................................... 12 4.1.
5.
Sizing Approach ................................................................................................ 12
Pipeline Pressure Rating........................................................................................... 14
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June 1998
5.1.
Source Pressure................................................................................................ 15
5.2.
MAOP................................................................................................................ 15
5.3.
Design Pressure................................................................................................ 15
5.4.
Test Pressure (Pt).............................................................................................. 16
5.5.
Normal Operating Conditions ............................................................................ 17
6.
Allowable Material Grades ........................................................................................ 17
7.
Corrosion/Erosion Allowances................................................................................. 17
8.
9.
7.1.
External Corrosion............................................................................................. 17
7.2.
Internal Corrosion.............................................................................................. 18
7.3.
Internal Erosion ................................................................................................. 18
Pipeline Wall Thickness ............................................................................................ 18 8.1.
th ....................................................................................................................... 18
8.2.
ta ....................................................................................................................... 19
8.3.
tm ...................................................................................................................... 19
8.4.
Wall Thickness .................................................................................................. 19
8.5.
Buckle Arrestors ................................................................................................ 20
Pipeline Strength Considerations ............................................................................ 20 9.1.
Design Loads .................................................................................................... 20
9.2.
Thermal Expansion Analysis ............................................................................. 22
9.3.
Design Load Combinations ............................................................................... 22
9.4.
Buckling Criteria ................................................................................................ 22
10. Pipeline Stability Criteria........................................................................................... 23 10.1. Design Current Velocities .................................................................................. 23 10.2. Directional Wave Information ............................................................................ 23 10.3. Hydrodynamic Forces ....................................................................................... 23
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10.4. On-Bottom Stability Design ............................................................................... 24 10.5. Vertical Stability................................................................................................. 24 10.6. Specific Gravity ................................................................................................. 24 10.7. Concrete Weight Coating .................................................................................. 25 11. Riser Design and Expansion Analysis ..................................................................... 26 11.1. Expansion Analysis ........................................................................................... 26 11.2. Riser Design...................................................................................................... 26 11.3. Marine Growth Allowance.................................................................................. 26 11.4. Platform Motion ................................................................................................. 27 12. External Corrosion Protection .................................................................................. 27 12.1. Corrosion Coatings............................................................................................ 27 12.2. Cathodic Protection ........................................................................................... 27 13. Pipeline Crossing....................................................................................................... 28 14. Pipeline Pigging ......................................................................................................... 28 15. Pipeline Stabilization, Trenching and Burial ........................................................... 28 16. Pipeline Shore Approach and Onshore Pipeline System ....................................... 29 17. Fishing and Dropped Object Protection .................................................................. 29 18. Safety Systems .......................................................................................................... 30 19. Calculations................................................................................................................ 30 19.1. Equation 1 ......................................................................................................... 30 19.2. Equation 2 ......................................................................................................... 31 19.3. Equation 3 ......................................................................................................... 31 20. Pipeline Design Report.............................................................................................. 33
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1.
Offshore Pipeline Design
June 1998
References The following publications form a part of this Practice. Unless otherwise specified herein, use the latest edition.
1.1.
MEPS–Mobil Engineering Practices
MP 16-P-01
Piping-General Design
MP 20-P-02
Line Pipe and Bend Material
MP 20-P-03
Offshore Pipeline Weight Coating
MP 20-P-04
Offshore Pipeline Installation
MP 20-P-05
Pigging Systems
MP 20-P-06
Offshore Pipeline Surveying
MP 20-P-07
Diving Operations
MP 20-P-08
Offshore Pipeline Crossings
MP 20-P-09
Corrosion Protection for Risers
MP 20-P-10
Pipeline Fittings
MP 20-P-12
Onshore Pipeline Installation
MP 20-P-14
Pipeline Corrosion Protection
MP 20-P-18
System Gauging, Hydrotesting & Disposal
MP 20-P-19
Drying & Purging
MP 20-P-20
Pipeline Shore Approach
MP 20-P-21
Trenching, Dredging & Backfilling
MP 56-P-01
Cathodic Protection for Offshore Steel Structures
MP 65-P-06
Submarine Flowlines
1.2.
Mobil Data Sheets
Mobil Data Sheets
Mobil Data Sheet Home Page
T2001C01
Offshore Pipeline Design - Pipeline Design - Customary Units
T2001M01
Offshore Pipeline Design - Pipeline Design - Metric Units
T2001C02
Offshore Pipeline Design - Pipeline Route Environment Data - Customary
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Units T2001M02
Offshore Pipeline Design - Pipeline Route Environment Data - Metric Units
T2001C03
Offshore Pipeline Design - Pipeline Fluid Property Characteristics Customary Units
T2001M03
Offshore Pipeline Design - Pipeline Fluid Property Characteristics - Metric Units
T2001C04
Offshore Pipeline Design - Pipeline Weight Coating Design - Customary Units
T2001M04
Offshore Pipeline Design - Pipeline Weight Coating Design - Metric Units
T2001C05
Offshore Pipeline Design - Corrosion Coating and Cathodic Protection Data - Customary Units
T2001M05
Offshore Pipeline Design - Corrosion Coating and Cathodic Protection Data - Metric Units
D2001C01
Offshore Pipeline Design - Documentation Requirements Sheet
1.3.
Mobil Tutorials
EPT 09-T-01
Facilities Piping
EPT 09-T-05
Piping-Code Selection Guide
EPT 10-T-07
Submarine Pipelines
EPT 10-T-08
Engineering Checklist for the Design, Manufacture and Construction of Submarine Pipelines
EPT 10-T-09
Submarine Flowline
1.4.
AGA–American Gas Association
AGA PR-179-9333
1.5.
AGA On-Bottom Stability Program
API–American Petroleum Institute
API RP 1111
Design, Construction, Operation, and Maintenance of Offshore Hydrocarbon Pipelines Second Edition
API RP 14C
Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms Fifth Edition; Errata - 1994
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API SPEC 5L
1.6.
June 1998
Specification for Line Pipe Forty-First Edition
ASME–American Society of Mechanical Engineers
ASME B31.4
Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols
ASME B31.8
Gas Transmission and Distribution Piping Systems
1.7.
CFR–U.S. Code of Federal Regulations
30 CFR 250
Mineral Management Service, Department of the Interior, Subchapter BOffshore
49 CFR 192
Transportation of Natural and Other Gas by Pipeline–Minimum Federal Safety Standards
49 CFR 195
Transportation of Hazardous Liquids by Pipeline
1.8.
DnV–Det norske Veritas
DnV RP E305
1.9.
On-Bottom Stability Design of Submarine Pipelines
MMS–Minerals Management Service, U.S. Department of the Interior
MMS NTL 91-02
Notice to Lessees and Operators of Federal Oil, Gas, Sulphur, and Salt Leases and Pipeline Right-of-Way Holders in the Outer Continental Shelf, Gulf Of Mexico OCS Region
1.10. NACE–National Association of Corrosion Engineers NACE MR0175
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Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment
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2.
Offshore Pipeline Design
June 1998
General The design of offshore pipelines, risers, pipelines routed across platforms, flowlines and flowline risers shall be in accordance with requirements of this MEP, unless superceded by more stringent local regulations. The Mobil Data Sheets for this MEP are part of this Practice. Where information is required but not shown, the contractor shall provide it and submit it to the Company for approval. •
The design shall satisfy all local and governmental laws, codes and regulatory requirements.
•
This MEP is based on domestic requirements, but could change for foreign locations. Any change shall have prior Company approval.
•
This Practice prescribes sound engineering, metallurgical and manufacturing practices proved in the offshore industry. If these requirements cannot be met, and have not been deleted by the job specifications, written notification of non-compliance, with explanations, shall be provided by the contractor. This notification shall then be evaluated and shall have Company approval before final acceptance of the pipeline system design.
Selection of the applicable piping code for the design of offshore pipelines and risers shall be in accordance with EPT 09-T-05. Any discrepancies between this MEP and the specifications and recommended practices selected by EPT 09-T-05 shall be brought to the Company's attention for resolution or approval before final acceptance of the pipeline system design.
2.1.
Transitions Unless otherwise specified in the job specifications, the transition between a pipeline system complying with this MEP and platform piping complying with MP 16-P-01 shall be located as follows:
2.2.
•
Incoming lines: upstream flange on the first block valve
•
Departing lines: downstream flange on the last block valve
Design Parameters Certain important parameters shall be considered in the design of a pipeline with regards to the pipeline system operational longevity. •
These include wind, wave and current forces plus other pertinent geological, geographical, environmental and operational conditions.
•
The design life of the pipeline system itself shall be as defined on the Mobil Data Sheets for this MEP.
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Offshore Pipeline Design •
3.
June 1998
The contractor shall define and present to the Company for review and approval any design criteria developed within this MEP. −
Data provided by the Company on the Mobil Data Sheets for this MEP shall be checked by the contractor and any data derived by the contractor shall be approved by the Company prior to use.
−
T2001C01 or T2001M01 in the Mobil Data Sheets for this MEP shall be initially completed, then revised as necessary, during the course of pipeline detail design.
Pipeline Route Selection The determining process of selecting a pipeline route involves at least three phases. 1. The initial phase requires the investigation of all possible route alternatives, within given limits. 2. The intermediate phase is a detailed hazard and archaeological survey. 3. The final phase constitutes a detailed study of the selected route. The major activities of each phase are described in the following Sections.
3.1.
Investigation of Route Alternatives •
An overall bathymetric chart of the area of interest is essential in the route evaluation process. Data shall be gathered on existing underwater objects such as coral reefs, sunken vessels, pilings, other pipelines or well casings.
•
Sea bottom topographic and geologic features shall be investigated as to the types of soil and their lateral and vertical distribution.
•
Environmental characteristics such as normal and storm winds, waves and currents shall be determined.
•
Other route selection considerations include:
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−
Local and federal regulations and codes
−
Requirements for pipeline burial or trenching
−
Shore approach and shore logistics
−
Pipeline construction equipment capability and availability
−
Navigation channel and ship traffic
−
Salinity and temperature distribution
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3.2.
Offshore Pipeline Design
June 1998
Hazard/Archaeological Survey A survey shall be undertaken to determine if any seafloor and subsurface features, manmade obstructions or archaeological sites that may adversely affect the pipeline route exist along the right-of-way. This survey is necessary before performing the detailed engineering study of the route. All areas affected by the pipeline installation and installation vessels, such as barge anchors and jack-up rig footprints, shall be included in the survey. Refer to MP 20-P-06 for further details and requirements.
3.2.1.
Required Instrumentation As a minimum, the survey shall include the continuous use of the following instruments:
3.2.2.
•
Echo sounder to measure water depth
•
Dual channel side scan sonar
•
Sub-bottom profiler
•
Magnetometer
•
Navigation positioning system that shall be correlated with the survey data
•
Equipment to recover core samples of near surface sediments at selected sites
Right of Way The pipeline right-of-way shall be surveyed as follows: •
•
3.2.3.
As a minimum, the survey shall be made along the centerline of the right-of-way and on two parallel lines: one on each side of the right of way, 300 m (985 ft) apart. −
Side scan coverage shall have 100 percent overlap.
−
Extra lines may be required for complete coverage of the survey area.
−
Intersecting lines transverse to the survey route shall be made every 300 m (985 ft).
The right-of-way width shall be increased to 1000 m (3280 ft) in areas that require anchor placement around other pipelines, wells or platforms.
Horizontal Control System A horizontal control system capable of providing accurate location fixes of the survey vessel to at least ± 5 m (16 ft) shall be used.
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Offshore Pipeline Design
3.2.4.
June 1998
•
The system shall include a real-time monitor to assist the ship's captain in running reasonably straight lines (within ± 7.5 m [25 ft] of the proposed tracklines). The system shall include a plotter capable of producing a hard copy of vessel tracklines, both real time and for post-processing.
•
Location fixes shall be taken at least every 150 m (490 ft). The navigation shall be interfaced with the other survey equipment.
•
The vertical control system shall be referenced to a recognized tide datum. For deep water surveys, underwater positioning shall be considered to accurately position sensor to fish.
ROV/Diving Operations It may also prove necessary to investigate anomalies discovered during the survey using divers or ROVs. These can accurately determine the potential hazard to the pipeline within the survey route. Refer to MP 20-P-07 for information on diving operations. Further archaeological survey requirements for the Gulf of Mexico are defined in MMS NTL 91-02.
3.3.
Engineering Study of the Selected Route A detailed engineering study of the selected route shall include the following elements:
3.4.
•
Vertical and horizontal alignment of pipe and curvature along the pipeline route
•
Soil conditions along the route, particularly in mudslide, sand-wave or rock outcrop areas
•
Identification of pipeline span areas along the route to minimize unsatisfactory spans and their associated corrective work
•
Long-term stability of the seabed and shore approach
•
Maximum wave forces and bottom currents that would affect the stability of the pipeline on the sea bed
•
Other environmental conditions affecting the pipeline, construction methods and equipment
•
For Gulf of Mexico surveys, an archaeological resource report, in accordance with MMS NTL 91-02
Defining Parameters Upon completion of the route selection, the following parameters shall be defined:
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4.
Offshore Pipeline Design
June 1998
•
Environmental data along the pipeline route shall be compiled on T2001C02 or T2001M02 in the Mobil Data Sheets for this MEP. These data include wave, current, oceanographic and soils criteria.
•
A weather window that is within the limiting environmental forces for the installation method shall be defined.
Pipeline Diameter Selection The internal fluid characteristics (liquid, gas or multiphase) are shown on T2001C03 or T2001M03 in the Mobil Data Sheets for this MEP. The selection of a pipeline diameter is a function of two groups of basic parameters. 1. The first group includes but is not limited to the production system, the overall transportation piping and the storage or distribution system. These parameters are not covered in this MEP; however, they shall be evaluated when determining the pipeline diameter. 2. The second group of parameters includes the route selection, required horsepower, line pipe material, installation and pipeline operation. Economic and technical evaluations of these parameters are necessary to derive an optimum pipeline diameter and wall thickness. However, the economic evaluation is not within the scope of this MEP.
4.1.
Sizing Approach When determining the internal diameter of the line pipe to be used in the pipeline system, both the fluid velocity and pressure drop shall be considered. The peak flow rate expected during the life of the facility shall be considered. Note that the initial flow rate may be less than the peak rate. Determination of pressure drop in a line shall include, but not be limited to, the effect of elevation differences, bends, valves and fittings. The pipeline fluid(s) velocity shall be constrained as follows: •
The fluid velocity in single-phase liquid lines shall vary from 0.9 m/sec to 4.5 m/sec (3 ft/sec to 15 ft/sec).
•
Single-phase gas lines typically shall have a pressure drop of 43-64 kPa per km (10-15 psi per mile). However, if a minimum outlet pressure is required by processing equipment or a compressor, then it shall govern the maximum allowable pressure drop. If a larger pressure drop is desired or cannot be avoided, the maximum flow velocity shall not exceed 12 m/sec (40 ft/sec).
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Offshore Pipeline Design •
June 1998
Gas/liquid two-phase lines shall not exceed the erosional velocity as determined below:
Ve = Ve =
4c ( Metric units ) (p m )0.5
c (Customary units ) ( p m ) 0.5
Where: Ve = Fluid erosional velocity, m/sec (ft/sec) pm = Density of the gas/liquid mixture, kg/m3 (lb/ft 3) c = Empirical constant (see the following table) Empirical Constant, c Service Type
Operational Frequency Continuous
Intermittent
100
125
Corrosion Free
--
--
Solids and/or Corrosive Contaminants2
--
--
Solids–Free Fluids Normal Conditions 1
NOTES: 1. This service type refers to solid-free fluids where no contaminants such as CO2 and H2S are anticipated. It also applies when corrosion is controlled by inhibition or where corrosion resistant alloys are employed. Values of c = 150 for continuous and c = 200 for intermittent service may be used with Company approval under the following caveat: specific data regarding the erosive/corrosive properties of the fluid shall indicate an erosion/corrosion free condition. 2. Where solids and/or corrosive contaminants are present or where "c" values higher than 100 for continuous service are used, periodic surveys to assess pipe wall thickness shall be considered. −
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If possible, the minimum velocity in two-phase lines shall be greater than 3 m/sec (10 ft/sec) to minimize slugging.
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Offshore Pipeline Design −
June 1998
The density of the two-phase fluid (gas/liquid mixture) may be calculated using the following derived equation:
pm =
p l Ql + p g Q g Ql + Q g
Where: Qg = Gas flow rate at flowing conditions, m3/hr (ft3/sec) pg = Gas density at flowing conditions, kg/m3 (lb/ft3) Q1 = Liquid (crude and water) flow rate at flowing conditions, m3/hr (ft3/sec) p1 = Liquid density at flowing conditions, kg/m3 (lb/ft3)
5.
Pipeline Pressure Rating This Section addresses the pipeline pressure rating. Important parameters such as maximum allowable operating pressure, design pressure and test pressure are all interdependent and necessary to describe the pipeline pressure rating. See Figure 1 for pressure nomenclature.
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Offshore Pipeline Design
June 1998
Figure 1: Pipeline Pressure Nomenclature Diagram
5.1.
Source Pressure The Source Pressure (Ps) at the pipeline system inlet, such as a compressor or pump discharge or wellhead pressure, is the basis for determining the pipeline pressure rating.
5.2.
MAOP The Maximum Allowable Operating Pressure (MAOP) includes the source pressure and by definition, Ps ≤ MAOP. The MAOP shall not exceed the following:
5.3.
•
The established pressure rating of the weakest component, including pipe
•
80 percent of the Test Pressure (Pt)
Design Pressure The design pressure is used when determining the Design Pressure Wall Thickness (th), Section 8.
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Offshore Pipeline Design
June 1998
The Design Pressure (P) is defined as follows: •
If the maximum depth (H) along the pipeline is 61 m (200 ft) or less below LAT, then: P = MAOP
•
If H > 61 m (200 ft), then:
P = MAOP + 9.806 pi (h + H ) − Pe ( Metric units) P = MAOP +
pi (h + H ) − Pe (Customary units) 144
Where: MAOP = Section 5.2, Pa (psi) pi = Density of internal fluid, kg/m3 (lb/ft3) H = Maximum pipeline depth below LAT, m (ft) h = Pressure Source height above sea level (can also be thought of as the height of pipeline inlet above LAT) Pe = External hydrostatic pressure, Pa(psi) = 9.806pw (X) (Metric units)
=
Pw ( X ) (Customary units) 144
pw = Density of external fluid, kg/m3 (lb/ft3) X = Minimum pipeline depth below LAT, m (ft)
5.4.
Test Pressure (Pt) The minimum test pressure shall be determined as follows: P1 = k (MAOP) Where: k = 1.25, 1.40 or 1.50 depending upon the type of commissioning test and the code used NOTE: Refer to EPT 09-T-05 for the applicable piping code. The test pressure shall not exceed any of the following: •
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The manufacturer's recommended maximum test pressure of any component within the pipeline system.
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5.5.
Offshore Pipeline Design
June 1998
•
The hoop stress within the pipeline wall resulting from the test pressure shall not exceed 90 percent SMYS without Company approval.
•
The combined hoop stress within the pipeline wall resulting from the test pressure hoop stress, in combination with the longitudinal stresses and tangential shear stress, shall not exceed 96 percent SMYS. Refer to Sections 9.1, 10 and 19.3 (Equation 3) of this MEP.
Normal Operating Conditions The pipeline MAOP shall not be exceeded during normal operations. Surge pressure, however, can produce a transient abnormal condition. It is caused by sudden velocity changes of the moving fluid stream within the pipeline. Therefore, surge calculations shall be made and adequate controls and protective equipment shall be included (see Section 19 of this MEP) so that the pressure rise due to surges shall not exceed the MAOP by more than 110 percent at any point in the pipeline system. Other conditions that could cause pressures higher than the pipeline MAOP shall be determined. The pipeline shall be appropriately protected for these with a safety system in accordance with Section 18 of this MEP. Riser design, riser clamp spacing and the offshore platform piping/slug catcher shall be designed to accommodate the liquid slugging caused by pigging the gas/liquid two-phase flow pipelines during normal or upset operating conditions.
6.
Allowable Material Grades Line pipe shall be in accordance with API SPEC 5L. Acceptable materials are API SPEC 5L Grades B, X42, X46, X52, X56, X60 and X65. Unless specifically approved by the Company, X70 and X80 material shall not be used.
7.
Corrosion/Erosion Allowances 7.1.
External Corrosion The external corrosion wall thickness allowance shall be zero for pipelines properly corrosion-coated and cathodically protected.
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7.2.
Offshore Pipeline Design
June 1998
Internal Corrosion The need for an internal corrosion wall thickness allowance shall be evaluated based on the fluid(s) transported. The internal corrosion allowance, if required by this evaluation, shall not be less than 2.6 mm (0.10 in). •
•
7.3.
Internal corrosion is recognized in the operation of pipelines and usually shall be controlled. −
A contaminant that will corrode the internal surfaces of pipe and its components in a piping system shall not be transported unless the corrosive effect of the contaminant has been investigated and adequate steps taken to mitigate internal corrosion.
−
Refer to NACE MR0175 for guidance.
−
Frequent scraping, pigging or sharing, dehydration, inhibition or internal coating may be used to limit internal corrosion.
If dehydration or inhibitors are used to control internal corrosion, sufficient coupon holders or other types of monitoring techniques shall be used to adequately determine the effectiveness of the internal corrosion control program. −
Inhibitors shall be selected that will not cause deterioration of any piping component.
−
The inhibitors shall be of proper quality and be used in sufficient quantity to mitigate internal corrosion.
Internal Erosion Wall thickness allowance for internal erosion shall be evaluated by the contractor and recommendations submitted to the Company for approval.
8.
Pipeline Wall Thickness Design Pressure Wall Thickness is the pipeline wall thickness capable of containing the design pressure (P) while maintaining the wall hoop stress within allowable limits.
8.1.
th th =
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P⋅D 2 ⋅ S y ⋅ E ⋅ F ⋅T
(Metrtic or Customary units )
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Offshore Pipeline Design
June 1998
Where: th = Design pressure wall thickness P = Design pressure, Pa (psi) (see Section 5.3) D = Outside diameter, mm (in) Sy = Specified minimum yield strength, Pa (psi) E = Weld joint factor F = Design service factor equal to or less than 0.72 for gas, liquid or two-phase hydrocarbon pipelines = 0.50 for all gas and two-phase risers or transportation piping on platforms = 0.60 for all liquid hydrocarbon risers or transportation piping on platforms T = Temperature derating factor NOTE: See ASME B31.4 or ASME B31.8 for clarifications of weld joint and temperature derating factors.
8.2.
ta The Internal Corrosion/Erosion Wall Thickness Allowance (ta) shall include the corrosion allowances as discussed in Section 7.2 and erosion allowances in Section 7.3.
8.3.
tm The Minimum Allowable Wall Thickness (tm) shall be defined as follows: Tm = (th + ta)
8.4.
Wall Thickness Unless otherwise approved by the Company, a standard API SPEC 5L wall thickness shall be selected as follows: t ≥ tm Where: t = The standard API SPEC 5L wall thickness capable of completing this expression, mm (in) The contractor shall consider the collapse and buckling strength of the pipe under the combined effects of hydrostatic pressure and bending during installation, as well as under
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June 1998
installed conditions. These conditions may mandate a wall thickness greater than that required in Section 8.1 and/or may necessitate an increase in the specified minimum yield strength (SMYS).
8.5.
Buckle Arrestors An evaluation shall be made to determine the need for buckle arrestors in laying deep water pipe.
9.
•
If needed, buckle arrestors shall be approximately 305 m (1000 ft) apart unless a closer spacing is specified.
•
Buckle arrestor design and materials shall be approved by the Company.
•
Buckle arrestors requiring fillet welds on the pipeline outside surface shall be avoided. Non-welded buckle arrestors or in-line welded that increase the wall thickness of the pipe are preferred.
Pipeline Strength Considerations 9.1.
Design Loads A stress analysis shall be performed, taking into consideration the following load conditions. (The hoop stress and cumulative longitudinal stresses shall not exceed the design factors defined in Sections 19.1 and 19.2.) •
•
For the design of the pipeline and riser system, the primary load scenarios are defined as follows: −
Loads during installation
−
Loads during hydrostatic testing
−
Loads during operation
For these scenarios, two basic loading conditions are to be applied: −
Functional loads
−
Functional loads plus simultaneously acting environmental loads
9.1.1.
Functional Loads Functional loads are incurred due to the existence of the pipeline and riser system and do not include environmental loads. Two functional loading conditions shall be considered:
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Offshore Pipeline Design •
•
9.1.2.
June 1998
The functional loads during installation are all loads up to construction completion and acceptance of the pipeline and riser, including hydrotesting (refer to MP 20-P-18), as follows: −
Weight: weight of pipe, coating, attachments and contents
−
Buoyancy
−
Pressure: internal, external, soil and hydrotest
−
Pipe Lay Forces: applied tension, lifting loads, ramp, stinger and pontoon loads
−
Trenching
The functional loads during operation are composed of the following elements and are generally considered static: −
Weight: weight of pipe, coating, attachments and contents
−
Buoyancy
−
Pressure: internal, external and soil
−
Expansion and contraction (product temperature): refer to Section 9.2
−
Prestressing: permanent curvature, permanent elongation and residual tension
Environmental Loads Environmental loads are the loads acting on the pipeline and riser system due to winds, waves, current and other environmental phenomena. These include loads due to third party operations such as fishing and shipping wake or propeller wash.
9.1.3.
•
The environmental loads are random in nature and shall be evaluated using probabilistic methods, based on available past records for the area.
•
They shall be taken as omni-directional unless environmental statistics determine otherwise.
•
Environmental loads shall be considered for both the installation and operational scenarios.
•
Environmental data is recorded on T2001C02 or T2001M02 in the Mobil Data Sheets for this MEP.
Hydrodynamic Loads Hydrodynamic loads can be summarized as follows: •
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Wave and current loads
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9.2.
Offshore Pipeline Design
June 1998
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Impact loads due to wave slamming
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Flow induced cyclic loads due to instability phenomena such as vortex shedding
Thermal Expansion Analysis A thermal expansion analysis shall be performed to determine the free end expansion and stress distribution along the pipeline. This analysis shall include the following: •
Longitudinal strain due to the temperature gradient, internal pressure and axial soil friction
•
Total stress and strain distribution
•
Stationary point and transition length
•
Displacement due to expansion loads resulting from the strain distribution
If the pipeline is laid over an irregular seabed terrain, the expansion loads can cause vertical buckling (upheaval buckling) of the pipeline. An upheaval buckling analysis shall be performed for each applicable pipeline.
9.3.
Design Load Combinations Sections 9.1 and 9.2 shall be used in a stress (strain) analysis of the most unfavorable relevant combination of principal stresses acting simultaneously on the pipeline during the above design loads. These planar principal stresses shall be combined to obtain an equivalent stress that shall not exceed the design factors defined by Section 19.3 of this MEP.
9.4.
Buckling Criteria The possibility shall be considered that one or more of the following buckling modes will occur: 1. Local buckling due to external pressure, axial force and bending moment 2. Propagation buckling due to external pressure 3. Compressive buckling: the effect of internal and external pressures introducing a compressive axial force at spans The pipeline system shall be designed to prevent local buckling under the most unfavorable combination of external pressure, axial force and bending moment. If buckle arrestors are required, refer to Section 8.5 of this MEP.
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10. Pipeline Stability Criteria An on-bottom pipeline stability analysis shall be performed after selecting the pipeline diameter and a wall thickness. DnV RP E305, AGA PR-179-9333 or equivalent environmental loading assessment techniques shall be applied. Current and wave induced water particle velocity and acceleration, typifying environmental conditions along the route, shall be used. Refer to the Mobil Data Sheets for this MEP. The number of positions necessary to adequately define the environment will depend on the length of the pipeline and the variations in water depth, seabed soil and meteorological conditions.
10.1. Design Current Velocities The design current velocities shall be based on the various contributing components such as tidal, storm surge and circulation currents. •
The directional distribution of the current velocity may be used in the stability design.
•
If no such information is available, the current shall be assumed to act perpendicular to the axis of the pipeline.
10.2. Directional Wave Information The directional distribution of the wave conditions may be accounted for when selecting the design wave-induced particle velocity. •
Extreme sea states from different directions shall be considered.
•
If no directional wave information is available, then the extreme wave conditions shall be assumed to act perpendicular to the axis of the pipeline.
10.3. Hydrodynamic Forces Hydrodynamic forces shall be calculated using Morrison's equations for determining the ability of the line to withstand predicted environmental loadings. •
The hydrodynamic forces acting on the pipeline shall be based on the significant wave height and the mean zero up-crossing period.
•
In shallow water or exposed segments of pipeline, an allowance shall be made for marine growth. This allowance shall be applied to the pipe outside diameter for determining the on-bottom pipeline stability.
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June 1998
Two scenarios shall be considered: the pipeline during installation and during its operational lifetime, as shown in Table 1.
Table 1: Stability Design Criteria Environment
Wave Dominated
Current Dominated
Hydrodynamic Condition
During Installation
During Operation
Wave
*5-year return storm
100-year return storm
Current
*1-year return condition
10-year return condition
Wave
*1-year return storm
10-year return storm
Current
*5-year return condition
100-year return condition
* Return storm or condition anticipated during the pipeline construction period
10.4. On-Bottom Stability Design The on-bottom stability design shall insure the structural integrity of the pipeline when exposed to the environmental loading. •
The significant static design approach shall be applied. This approach takes short segments of pipeline along the pipeline route—these segments are sufficiently short to be considered rigid.
•
A pipeline free-body diagram is statically solved for each of these segments using the significant wave height and the current condition in the previous paragraph. The lateral soil resistance to pipeline movement by these hydrodynamic forces shall have a 1:1 safety factor.
10.5. Vertical Stability The pipeline shall be checked for vertical stability, for example, possible sinking or flotation. If required, soil liquefaction shall also be considered.
10.6. Specific Gravity The specific gravity of a pipeline shall not be less than 1.15 unless otherwise specified in the job specifications or required by the environmental conditions: SGp ≥ 1.15 SGp = wa/wd Where: SGp = Specific gravity of an empty submerged pipeline, a dimensionless ratio
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wa = Total in-air weight of an empty pipeline, per unit length, including corrosion and weight coatings, N/m (lbs/ft) wd = Weight of displaced water from submerged empty pipeline, per unit length, including weight coating, N/m (lbs/ft)
10.7. Concrete Weight Coating Using the submerged weight per unit length (ws) derived from this Section, calculate the concrete weight coating thickness needed to obtain this required submerged weight per unit length. Refer to Figure 2 for nomenclature. The air weight (wa), the submerged weight per unit length (ws), the concrete thickness and concrete density shall be specified in the Mobil Data Sheets for this MEP. Both the thickness and weight of the corrosion coat shall be included in these calculations. The fabricated line pipe with concrete coating shall be weighed and checked to ensure the submerged design weight per unit length has been achieved.
Nomenclature Lp =
Line Pipe Joint Length, m (ft)
Di =
Inside Diameter of Line Pipe, mm (in)
Lc =
Concrete Weight Coating Length, m (ft)
De =
Outside Diameter of Corrosion Coating, mm (in)
D =
Outside Diameter of Line Pipe, mm (in)
Dc =
Outside Diameter of Weight Coating, mm (in)
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Figure 2: Weight Coated Line Pipe Dimensions
11. Riser Design and Expansion Analysis 11.1. Expansion Analysis Heat loss calculations shall be performed to determine the pipeline temperature profile that will be used in performing the thermal expansion analysis. •
An expansion analysis shall be conducted to determine the amount of thermal growth of the pipeline and the resulting stress.
•
Expansion loops may be required to compensate for expansion and to reduce thermal stresses.
•
Pipeline expansion shall be based on the minimum water temperature and maximum operating temperature and pressure determined from the thermal analysis. This expansion shall be modeled as a deflection toward the riser.
11.2. Riser Design Riser design shall be based on the worst case of the combinations of operating conditions, environmental loads and expansion stresses. •
Wave and current loads shall be calculated from Stokes Fifth Order theory adapted to the risers.
•
Maximum combined wave characteristics for the 100-year return period storm and the maximum current speed shall be used to calculate riser loads.
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Shielding effects by the platform jacket may be considered, where applicable.
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Hydrodynamic coefficients to be employed in the analysis shall be the same as in the Platform Jacket Analysis, unless otherwise specified in the Mobil Data Sheets for this MEP.
11.3. Marine Growth Allowance Allowance for marine growth shall be used when determining the riser diameter for environmental loads. •
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Unless otherwise specified, marine growth shall be assumed between the mud line and the (+) 1.8 m (6 ft) elevation.
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Offshore Pipeline Design •
June 1998
Refer to the Mobil Data Sheets for this MEP for marine growth thickness details.
11.4. Platform Motion Platform motion shall be accounted for by inputting deflections at riser support points.
12. External Corrosion Protection 12.1. Corrosion Coatings The acceptable type of coating system for offshore pipeline systems is fusion bonded epoxy (FBE). Refer to MP 20-P-14 and MP 20-P-09 for design details. •
The FBE system is preferred for corrosion protection of submerged steel pipelines.
•
If not available, alternatives shall be submitted for prior Company approval.
•
Refer to the Mobil Data Sheets for this MEP for pipeline corrosion coating details.
Special riser corrosion protection coatings for the splash zone areas shall be provided. Refer to the Mobil Data Sheets for this MEP for riser splash zone corrosion coating details.
12.2. Cathodic Protection The preferred system is sacrificial anodes. Pipeline anodes shall consist of zinc or proprietary aluminum-zinc anode bracelets. Exact anode composition and spacing calculations shall be submitted to the Company for approval. Refer to MP 56-P-01 and the Mobil Data Sheets for this MEP for design details. •
Protection criteria, system design and calculations shall be accordance with MP 56-P01 and API RP 1111. Spacing between anodes shall not exceed 305 m (1000 ft).
•
Design consideration shall be given to the following:
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−
Minimizing electrical interference of other pipelines and/or structures
−
Water depth
−
Water temperature
−
Water current (motion) and pipeline temperature
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13. Pipeline Crossing Pipeline crossings shall be avoided whenever possible. If a pipeline crossing is necessary, the following requirements shall be considered: 1. The vertical separation between lines in the as-laid condition shall be a minimum of 1/2 m (1.6 ft). 2. Whenever possible, the crossing design shall be such that the smaller pipeline crosses over the larger pipeline. 3. The crossing design shall prevent relative motion of one line from influencing the other line. 4. The crossing design shall be approved by the Company and by the owner and/or operator of the pipeline being crossed. 5. Protection for crossings from impact (trawl, boards, etc.) shall be evaluated. 6. Cathodic protection of all pipelines involved in the crossing shall be considered. 7. Refer to MP 20-P-08 for design details.
14. Pipeline Pigging The pipeline and its risers shall be piggable, with pig launching and receiving capabilities unless otherwise stated in the job specifications. Refer to MP 20-P-05, MP 20-P-10 and MP 20-P-19 for design details.
15. Pipeline Stabilization, Trenching and Burial Pipelines shall be placed below the seabed as required by applicable local and governmental marine pipeline codes and as specified by the Company (See EPT 09-T-05). Requirements shall be coordinated with the pipeline stabilization requirements and the selected methods approved by the Company. Refer to MP 20-P-21 for design requirements. •
Design and procedures for jetting, trenching or burial operations to lower pipeline below the seabed shall ensure that excessive stresses are not imposed on the pipeline due to the formation of unsupported spans or contact between the pipeline and trenching/jetting equipment. Post-lay jetting, trenching or burial operations shall be continuously monitored by ROV, fixed video cameras or divers.
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Inspection using ROV or other approved methods shall be made following the lowering operation activities to ensure that no unacceptable spans exist and that the design requirements have been met.
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Pipeline stabilization shall use sandbags, rock dumping, grout mattresses and/or the jetting, trenching or burial requirements above.
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Sandbags used for stabilization shall be 3:1 sand/cement mix. The ends of the bags shall be folded and sewn.
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Rock dumping shall be designed to minimize impingement damage to the pipeline. Where necessary, a sand pad shall be placed over the pipeline prior to rock placement. Rock size shall be selected to ensure that the final cover profile over the pipeline and fill, around or under the line, can be achieved.
16. Pipeline Shore Approach and Onshore Pipeline System Pipelines shall be designed and installed to meet the local and governmental pipeline codes for shore approaches and onshore pipeline codes for their specific service (liquid or gas). The onshore pipeline, pig receiver and associated piping shall be designed to accommodate any slugging that results from pigging a gas/liquid, two-phase flow pipeline during normal or upset operating conditions. In the event a pipeline anchor block is required, all necessary calculations shall be performed to properly size the anchor block, taking into consideration soil characteristics, piping, slug-catcher layout and size, pipeline installation parameters, pipeline operation and environmental conditions. Refer to MP 20-P-12 and MP 20-P-20 for further design requirements.
17. Fishing and Dropped Object Protection In water depths that permit fishing with trawling gear, the pipeline shall be protected from snag or designed for snag loads. This protection shall be provided along the entire pipeline subjected to the trawl gear snagging. A flowline section adjacent to a subsea tree or manifold, platform or well caisson that will be frequented by drilling rigs, work boats or other marine vessels shall be protected against dropped objects from these vessels. The design of this protection shall be in accordance with Section 18 and shall be approved by the Company.
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18. Safety Systems The pipeline system shall be protected by a safety system meeting the requirements of API RP 14C, 30 CFR 250, 49 CFR 192 and 49 CFR 195. •
This system shall be designed by the pipeline design contractor unless otherwise specified in the job specifications.
•
The pipeline design contractor shall coordinate with the platform process contractor and with the Company to ensure this pipeline safety system becomes a part of the platform process safety system.
•
An engineering flow diagram shall be prepared. −
It shall show the pipeline system, safety system and all related piping systems and controls at each end of the pipeline.
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It shall include any connection to the pipeline system by other pipeline systems, their safety system and related piping systems and controls.
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The diagram shall be approved by the Company before purchase or construction.
19. Calculations 19.1. Equation 1 For pipelines and risers, the hoop stress due to the difference between internal and external pressure shall not exceed the following:
Sh =
PD 2 (t − t a )
S h ≤ K h S y ET These equations shall not be used when determining the pipeline wall thickness due to internal pressure (see Sections 8.1 and 16). Where: Sh = Hoop stress, Pa(psi) Sy = SMYS
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Kh = Hoop stress design factor from Table 1 P = Design pressure, Pa (psi) D = Outside diameter of pipeline, mm (in) t = Standard wall thickness, mm (in), Section 8.4 ta = Wall thickness allowance for corrosion and erosion, Section 8.2 MT = The absolute value of the manufacturer's pipe wall underthickness tolerance, /100 (see Note 1) E = Weld joint factor (see Note 2) T = temperature derating factor (see Note 2) NOTES: 1. See API SPEC 5L. 2. See ASME B31.4 or ASME B31.8.
19.2. Equation 2 For pipelines and risers, the cumulative longitudinal stress (i.e. bending, expansion, lay and residual tensions) shall not exceed the following:
Sl ≤ Kl S y Where: S1 = Maximum longitudinal stress K1 = Longitudinal stress design factor from Table 2
19.3. Equation 3 For pipelines and risers, the hoop stress and cumulative longitudinal stresses will be combined and the combined stress shall not exceed the following:
[S l + S 2
2 h
− S l S h + 3S s ] 0.5 ≤ K c S y ( Metric or Customary)
Where: Sl = Equation 2 Sh = Equation 1
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Ss = tangential shear stress, Pa (lbs/in2) Kc = combined stress design factor from Table 3
Table 2: Design Factors for Pipelines and Risers Pipeline Section Load Case
Restrained
Unrestrained
Riser Section
Hoop, Kh
0.72
0.72
See Note 1
Expansion
--
0.72
0.72
Longitudinal, Kl
--
0.80
0.80
NOTE: In accordance with ASME B31.4 and ASME B31.8, the factor is 0.6 for oil and 0.5 for gas and two-phase risers.
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Table 3: Combined Stress Design Factor, Kc NOTE: The Design Factors shown are considered the maximum for static conditions. For dynamic cases or unusual circumstances, these values could decrease.
Load Case
Pipeline Section
Riser Section
Over Bend
0.90
--
Sag Bend
0.85
--
Tensile
0.90
--
0.75
--
0.96
0.96
0.67
0.67
0.90
0.90
Lay:
Trenching Hydrostatic Testing Installation Aids Operation
*
*Installation aids are not an integral part of the pipeline. They include padeyes on pulling heads, knee braces, etc.
20. Pipeline Design Report A pipeline design report shall be prepared which documents the design basis, calculations, assumptions, criteria and analysis for each pipeline system.
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