Chapter 2-eng.pdf

JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

CHAPTER 2 PIPELINE DESIGN CONTENTS Page No. 2.1 2.2

2.3

2.4

2.5 2.6 2.7

2.8 2.9

2.10

2.11 2.12

Approved:2009

Codes and Standards Design Stages 2.2.1 Front End Design 2.2.2 Conceptual Design 2.2.3 Detailed Design Pipeline Routing Offshore 2.3.1 Preliminary Routing 2.3.2 Navigation 2.3.3 Shore Approaches 2.3.4 Existing Pipelines and Structures 2.3.5 Platform approaches and riser location 2.3.6 Topographical and Hydrographic Survey 2.3.7 Soil Data 2.3.8 Final offshore routing Pipeline Routing Onshore 2.4.1 Considerations 2.4.2 Route Information 2.4.3 Permanent Right-of-Way 2.4.4 Block Valve Stations 2.4.5 Final Routing Pipeline Routing Tolerance Requirements Geotechnical Site Investigation 2.6.1 Planning Materials 2.7.1 Carbon Steel 2.7.2 Glass Reinforced Plastic 2.7.3 Corrosion Resistant Alloys 2.7.4 Plastics 2.7.5 Flexibles Leak Detection and Isolation Systems Diameter Selection 2.9.1 Basics 2.9.2 General Considerations 2.9.3 Velocity Limitations 2.9.4 Recommended Standard Operating Pressures 2.9.5 Sizing Criteria for Liquid Lines 2.9.6 Sizing Criteria for Gas Lines 2.9.7 Sizing Criteria for Two-Phase Lines 2.9.8 Pressure Losses in Valves and Fittings Wall Thickness Selection 2.10.1 Basics 2.10.2 General Considerations 2.10.3 Hoop Stress Sizing Criterion 2.10.4 Code Transition 2.10.5 Pipe Wall Thickness Tolerances 2.10.6 Minimum Nominal Pipe Wall Thickness Standardisation of Linepipe Environmental Data 2.12.1 Waves 2.12.2 Currents 2.12.3 Water Depth 2.12.4 Ambient Temperatures 2.12.5 Operating Temperatures 2.12.6 Marine Growth

3 3 4 4 5 6 6 7 7 8 8 10 10 10 11 11 12 12 12 12 12 13 14 17 17 18 19 19 19 19 20 20 20 21 22 22 24 24 24 25 25 25 26 27 28 28 29 29 29 31 32 32 33 33

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

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2.13 Stresses and loads 2.13.1 General 2.13.2 Stresses 2.13.3 Strain based design 2.13.4 Hydrostatic Pressure and Pipeline Collapse during Installation 2.13.5 Wave and current loads 2.13.6 Wind Forces 2.13.7 Point and distributed loads 2.13.8 Thermal loads 2.13.9 Unsupported spans 2.14 On-Bottom Stability 2.14.1 General 2.14.2 Analysis 2.14.3 Concrete Weight Coating 2.14.4 Shore Approach 2.15 Riser design 2.15.1 Components 2.15.2 Riser coating 2.15.3 Passive Fire Protection 2.15.4 Pipeline approach and riser bend angle 2.15.5 Riser Clamp Positions 2.16 Corrosion 2.16.1 Design Life 2.16.2 Composition of Transported Medium 2.16.3 Environmental Conditions 2.16.4 Corrosion Inhibitors 2.16.5 External corrosion coatings 2.16.6 Cathodic Protection 2.16.7 Strength Assessment 2.17 Installation Analysis 2.18 Pipeline pigging 2.18.1 Internal Diameter Inspection Pigs 2.18.2 Cleaning and Batching Pigs 2.18.3 Corrosion Inspection Pigs 2.18.4 Pinger Pigs 2.18.5 Pipeline Design for Pigging 2.18.6 Pig Launcher and Receiver 2.18.7 Pipelines Requiring Pigging Facilities 2.19 Pipeline Material Procurement 2.19.1 General 2.19.2 Linepipe and bends 2.19.3 Flanges 2.19.4 Butt-weld fittings and Barred Tees 2.19.5 Launcher and Receivers. 2.20 Pipeline Design Data 2.20.1 Allocation of PID number for new pipelines 2.20.2 Pipeline Data Sheets 2.21 Hydrostatic Testing 2.21.1 Testing Requirements 2.21.2 Test Equipment and Instrumentation 2.21.3 Determination of Residual Air Volume in Pipeline 2.21.4 Hydrostatic Leak Test Evaluation 2.21.5 Location of Leaks during Hydrostatic Testing 2.21.6 Testing After New Construction 2.21.7 Hydrostatic Testing of Internal Pressure Piping 2.21.8 Testing of Fabricated Items 2.21.9 Testing of Replacement Pipe Sections.

Approved:2009

33 33 33 36 38 40 41 42 43 43 47 47 47 48 49 50 50 51 51 52 52 53 53 54 54 55 55 55 56 56 57 57 57 59 59 59 60 61 61 61 61 62 62 62 62 62 62 64 64 65 65 66 70 70 71 72 72

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2.1

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

Codes and Standards The basic design standards being followed are: ASME B.31.4:

Liquid transportation systems for hydrocarbons, liquid petroleum gas, anhydrous ammonia, and alcohols

ASME B.31.8:

Gas transmission and distribution piping systems

DNV ‘81 Rules: Rules for Submarine Pipeline Systems A comprehensive list of applicable codes and standards is included as reference in section 1.8. Unless otherwise stated this document assumes the pipe material to be carbon steel. SI units are used throughout the text although, where deemed useful, imperial or oil field units are also provided. 2.2

Design Stages Design of offshore pipelines is usually carried out in three stages: conceptual engineering, preliminary engineering, and detail engineering. During the conceptual engineering stage, issues of technical feasibility and constraints on the system design and construction are addressed. Potential difficulties are revealed and non-viable options are eliminated. Required information for the forthcoming design and construction are identified. The outcome of the conceptual engineering allows for scheduling of development and a rough estimate of associated cost. The preliminary engineering defines system concept (pipeline size and grade), prepares authority applications, and provides design details sufficient to order pipeline. In the detail engineering phase, the design is completed in sufficient detail to define the technical input for all procurement and construction tendering. A complete pipeline design includes pipeline sizing (diameter and wall thickness) and material grade selection based on analyses of stress, hydrodynamic stability, span, thermal insulation, corrosion and stability coating, and riser specification. The following sections detail the specific requirements for each design stage.

Approved:2009

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

FIGURE 2 OFFSHORE PIPELINES CATEGORY

2.2.1

Front End Design During the front-end design of a pipeline, the transport requirements are defined in terms of product, throughput and pressure/temperature regimes. The Project Development Plan usually documents the preliminary size, routing options and design philosophy and includes basis for design parameters such as design life, fluid composition, environmental and operating conditions.

2.2.2

Conceptual Design The following activities are normally carried out during the conceptual design of an offshore pipeline: •

Survey route,

•

Select the pipeline route and prepare drawings, including riser location

•

Perform a brief environmental impact assessment,

•

Finalise the pipeline diameter,

•

Select pipeline material and corrosion prevention methods,

•

Select pipeline and riser wall thickness,

•

Check pipeline in-situ stresses

•

Select riser clamp positions, check riser stresses and prepare riser drawings,

•

Determine concrete weight coating thickness and density,

•

Prepare pipeline and riser installation feasibility report,

Approved:2009

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Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

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•

Prepare Process Engineering Flow Diagram, showing pig traps, overpressure protection system and leak detection system,

•

Prepare bill of long lead materials,

•

Prepare conceptual design report.

•

Determine pipeline criticality and consequence of failure

•

Prepare MRP and ensure elements required to carry out maintenance/inspection activities are included in the design.

The following activities are normally carried out during the conceptual design of an onshore pipeline:

2.2.3

•

Select preliminary route based on 1:10,000 or relevant scale maps,

•

Perform a quantitative risk assessment (optional)

•

Perform an environmental impact assessment (optional)

•

Determine the pipeline diameter size,

•

Select pipeline material and corrosion prevention methods,

•

Select pipeline wall thickness,

•

Prepare Process Engineering Flow Diagram, overpressure protection and block valves,

•

Prepare bill of long lead materials,

•

Prepare conceptual design report.

•

Determine pipeline criticality and consequence of failure

•

Prepare MRP and ensure elements required to carry out maintenance/inspection activities are included in the design

showing

launchers,

receivers,

Detailed Design The following activities are normally carried out during the detailed design of an offshore pipeline: •

Finalise alignment sheets, arrangement drawings,

•

Select pipeline installation method (laying, towing, etc.),

•

Perform pipeline installation analysis of the preferred method,

•

Select riser installation method,

•

Perform riser installation analysis of preferred method,

•

Carry-out pipeline crossing design,

•

Design cathodic protection system,

•

Prepare welding specifications,

Approved:2009

approach

drawings,

riser

drawings,

and

general

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

•

Prepare pre-commissioning procedure,

•

Prepare operating, maintenance and inspection manual,

•

Prepare final bill of materials,

•

Prepare detailed design report.

The following activities are normally carried out during the detailed design of an onshore pipeline:

2.3 2.3.1

•

Detailed survey by XGM of the preliminary route,

•

Select final route,

•

Prepare alignment sheets,

•

Select and peg the final pipeline route,

•

Design cathodic protection system,

•

Design major road and river crossings,

•

Determine pipeline lowering into trench parameters,

•

Prepare welding specifications,

•

Prepare pre-commissioning procedure,

•

Prepare operating, maintenance and inspection manual,

•

Prepare final bill of materials,

•

Prepare detailed design report

Pipeline Routing Offshore Preliminary Routing Approximate routing should be indicated on hydrographic charts (scale 1:10,000), showing structures, pipelines and other features. For riser positioning (platform) orientation drawings or platform approach drawings provide useful information. The minimum allowable horizontal curvature of a pipeline depends on various factors, such as installation method, diameter, wall thickness and operating conditions. For submarine pipelines, the minimum radius of curvature at bends in the route is governed by two factors: •

The curve radius which can be maintained in equilibrium during installation.

•

The equivalent stress in the pipe wall during operation.

As an approximation, soil friction enables a pipeline curve radius, R, if R is greater than the term,

Approved:2009

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

R=

T fw

where:

T = on bottom lay tension f = lateral pipe-soil friction coefficient w = submerged weight of pipeline when empty Conservative values of T and f shall be adopted since the above equation ignores pipe stiffness. Special consideration shall be given to route curvatures near pipeline 'free ends' (e.g. start up/lay down). The effect of route curvature on the equivalent stress in the pipe wall shall be checked on a case by case basis. Generally, bending stresses of up to 10% of SMYS will have no adverse effect. In the absence of suitable data, the following values may be used for conceptual design purposes: Pipe diameter Less than DN 250 DN 250 DN 450 Over DN 450

Minimum radius (m) 1000 2000 3000

Pipeline alignment sheet drawings shall be referenced to the system, and shall show all pertinent route co-ordinates (e.g. start up/lay down, tangent points, intersection points, centre points of curvature, kilometre posts). For pipeline routing tolerance requirements see Section 2.5. 2.3.2

Navigation Marine traffic may constitute a hazard during and after construction. The primary risk of damage is by dragging anchors or "sawing" anchor cables. Parts of waterways where navigation is difficult, mooring and anchoring locations should be avoided as pipeline crossing sites. To reduce the risks of damage by anchors, in such areas, burial of pipelines may be advisable.

2.3.3

Shore Approaches The pipeline shore approach location may be influenced by the existence of industrial, commercial or residential installations on the shore or banks. Not only may such installations prohibit the routing of the pipeline in the neighbourhood, but the availability of a work area on the bank may prohibit the construction or eliminate certain construction method as e.g. bottom pull. Obviously, a concentration of rocks, barge tie-up points, gravel or sand pits, and residential, commercial or industrial installations has a negative effect on the crossing site.

Approved:2009

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2.3.4

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

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Existing Pipelines and Structures Crossing of existing pipelines require special measures such as additional dredging, jetting down existing line, sandbagging or installing saddles, to avoid over-stressing and cathodic protection system interference. Selection of a route with fewer crossings could therefore be financially attractive. Offshore platforms normally are, or will be, concentration points for pipelines and shipping, and also present navigational obstructions to construction equipment. The pipeline route should, therefore, be chosen at a practical distance (say 100m) from those structures which are unrelated to the pipeline. Pipelines close to offshore platforms should, as far as possible, be arranged in corridors to facilitate the anchoring of vessels for support and future construction activities at the platform. The pipeline route shall be selected with due regard to safety of the public and personnel, protection of the environment, and the probability of damage to the existing submarine pipeline or other facilities such as electrical cables shall take into design consideration. Line crossings near platforms should be prevented as they may jeopardise future riser repairs or relocations. The design should ensure that crossings are sufficiently protected both from a mechanical and cathodic protection point of view.

2.3.5

Platform approaches and riser location In deciding where to approach the platform and where to locate the riser, the following factors should be considered: •

The location of the facilities on the platform to be connected to the pipeline.

•

The location of the available riser clamps, J-tubes, bending shoes, or guide rails.

•

Other existing and future marine pipelines, and the number of pipeline crossing required.

•

Accessibility of the riser location to the lay/construction barge.

•

The location of existing boat landings. In general, risers should not be located near boat landings because of possible boat-inflicted damage.

•

Install large diameter risers near jacket legs (in the "shadow") to minimise stresses on bracings.

•

Angle of pipeline approach.

•

The number and position of cross bracings. Since riser clamps make use of the horizontal bracings these may influence the riser location.

•

Rig access to the drilling and wellhead platforms is not hindered by the pipeline. A minimum clearance of 15 m between spud cans and pipeline should be available.

•

Existing Jack-up rig footprints: clearance from the edge of the footprint to the proposed pipeline axis should be equivalent at least to the depth of the footprint at the point nearest to the pipeline route, plus 3 pipeline diameters or 1.0m (whichever is the greater), plus the tolerance for laying.

Approved:2009

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RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

Consideration is to be given to reduce risk of damage from dropped objects or dragged anchor wires by appropriate selection of route and protection of pipeline by mattresses.

In order to establish the number of risers which can be set at a given platform the average spacing between adjacent risers and the seabed approach angles need to be considered. The minimum approach angle to a platform face shall be 30° but for practical reasons the approach angle should be as near as possible to 90°. The minimum angle between adjacent riser approaches on the seabed should be 4°. The minimum spacing between adjacent risers (measured from centrelines) on a given jacket face is dependent upon water depth and shall be as follows: a) Water depth: From 0 up to 24 metres DN 100, 150, 200

:

1.0 m

DN 250, 300

:

1.2 m

DN 400, 500

:

1.8 m

DN 600, 700

:

2.1 m

b) Water depth: From 24 up to 46 metres DN 100, 150, 200

:

1.2 m

DN 250, 300

:

1.5 m

DN 400, 500

:

2.1 m

DN 600, 700

:

2.4 m

c) Water depth: 46-76 metres DN 150, 200

:

1.5 m

DN 250, 300

:

1.8 m

DN 400, 500

:

2.4 m

DN 600, 700

:

2.7 m

When pipelines have to approach the jacket with angles greater than 30o from the central axis the spacing between the risers should be increased by 0.3 m to allow more space between the lines on the seabed. If the direct approach of a pipeline is hampered by the future position of a jack-up rig, doglegs can be laid consisting of: •

90o bend with minimum radius of 5 times the outside diameter.

•

section of 25 to 30 m

Doglegs should also be used in preference to tight curved approaches to jackets and provide a means of allowing for thermal expansion in addition to that provided by riser deflection below the bottom clamp.

Approved:2009

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Chapter 2: Pipeline Design

Revision: 00

A very important item for riser locations is the design of a complex layout. Several platforms together form a complex, which should have a staggered layout along a straight line (spine) in order to: •

free as much of the jacket faces as possible for risers,

•

allow easy barge access,

•

position different production functions along the spine, so that future extension of any function is perpendicular to the spine,

•

allow for new functions to be installed along the spine,

Often a dedicated riser platform is installed to supply additional riser capacity (with scraper barrels and manifolds) and/or to reduce the overall risk levels. For new developments and extensions of existing complexes a careful study of the new layout should be made in conjunction with anchor patterns (especially the drilling rigs) and pipeline approaches. 2.3.6

Topographical and Hydrographic Survey To select the most satisfactory route for an underwater pipeline and to obtain environmental data necessary for design, information concerning the history, geology, hydrology and degree of marine activity should be gathered. When a preliminary routing is chosen, after evaluation of alternatives, the following detail surveys should be made: •

Side-scan sonar to detect existing lines, ship wrecks, debris etc.

•

Pinger survey for sub-bottom profile.

•

Bathymetric survey for water depth measurements.

Upon completion of the pipeline, it is normal practice to perform an "as-built" side scan and bathymetric survey to determine its final location. 2.3.7

Soil Data Soil data will indicate the necessity and difficulty of excavation and soil stability. If the data is inconclusive, then sampling and boring with analysis by a qualified consultant may be required. If the seabed or river bed is unstable, as for example, in mud lump or mud slide areas around river deltas, or there is coral or rock, the pipeline should, if possible, be routed around these areas (refer section 2.6).

2.3.8

Final offshore routing Based on the information gathered a final routing can be selected and drawn on alignment sheets and platform approach drawings, for approval. The alignment sheets usually have a horizontal scale of 1:5,000 and vertical scale of 1:100 and provide details on the pipeline. The platform approach drawing usually has a scale 1:100. For pipeline routing tolerance requirements see Section 2.5.

Approved:2009

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2.4 2.4.1

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

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Chapter 2: Pipeline Design

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Pipeline Routing Onshore Considerations The proximity of residential areas and major roads poses safety and environmental limitations in the routing of pipelines. Where possible these areas should be avoided. Prime drilling reserves should also be left clear. Obstructions to be avoided include: •

Buildings

•

Hard-surfaced areas

•

Roads (where possible)

•

Wooded or jungle areas

•

Other pipelines

•

Rivers (where possible)

•

Swampy or marshy areas

•

Beach areas (erosion problems)

During the route selection process, consideration of the risk contours to residential areas shall be made. The risk contours should consider all future developments and provide a risk level. Refer to "DNV - Technical Guidelines". Pipelines should never be routed directly above or below existing pipelines. Wherever possible, pipelines shall be buried. Although this increases installation costs it reduces external corrosion and future maintenance and does not restrict maintenance vehicle access. There are occasions where existing above ground pipe racks can be used but efforts shall be employed to reduce these existing racks. After taking account of the above considerations, pipe routings should be: •

as straight as possible (eases installation and reduces cost)

•

follow natural or logical routes

•

utilise existing rights of way (to minimise soil erosion)

River crossings should be straight rather than bowed or severely angled across the river. Where a change of direction or a shift in line becomes inevitable it is good practice to combine this with other requirements such as shutdown valves, connections to other facilities, expansion legs and to do so at points where the line can run parallel to existing pipeline(s). After selecting the preliminary route, the government shall be consulted to determine any future development plans along or close to the proposed route and to gain approval of the route. For all significant onshore pipeline projects, an Environmental Impact Assessment (EIA) and Quantitative Risk Assessment (QRA) shall be carried-out before finalising the route.

Approved:2009

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2.4.2

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

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Chapter 2: Pipeline Design

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Route Information To identify the areas described above, topographical background maps shall be used in conjunction with drilling reserve maps. Aerial photographs are a good source of information when choosing a preliminary route especially with regard to jungle or other natural obstacles. When the preliminary routing drawings have been prepared a site survey shall be carried out. There are no exceptions to this rule. Where thick jungle or undergrowth prevents 'walking the line' consideration should be given to altering the route accordingly. During the site visit actual construction dimensions shall be obtained from fixed points such as well heads, fence lines, centrelines of roads, buildings or any other suitable 'hard' point.

2.4.3

Permanent Right-of-Way A permanent Right-of-Way (ROW) corridor of 8 m (some 4 m each side of the line) is normally acquired for the pipeline ROW. This corridor shall allow access to vehicles for maintenance (e.g. cathodic protection monitoring), patrolling and repair purposes. If possible the pipeline ROW corridor shall preferably be 16 m wide. This wider corridor shall prevent (building) activities close to the pipeline. However, it does not mean that the full corridor needs to be kept clear of vegetation.

2.4.4

Block Valve Stations All onshore pipelines should have sectionalising block valve stations at maximum intervals as defined by the ASME B31.4 and B31.8 codes to allow isolation during an emergency. It is generally good practice to install valves upstream and downstream of river crossings, particularly for oil lines.

2.4.5

Final Routing The final routing should be drawn on alignment sheets, which include pipeline details. The alignment sheets shall be discussed and agreed upon with the project matrix. In addition approval should be obtained from all relevant parties.

2.5 2.5.1

Pipeline Routing Tolerance Requirements General Pipeline routing should be addressed at the very beginning of any new pipeline project. The route selection should always be progressed with open dialogue between marine operations, XGM (topographical department) and the pipeline engineering group in order that the relevant information and requirements of these functions are considered and addressed. Where a proposed route from an existing platform is in the general direction of any existing line the route should follow close and parallel to such existing pipeline corridor for as long as practically possible, as this will minimise the impact on marine operations, such as the anchoring patterns at existing platforms. Where pipelines are laid along existing pipeline corridors the offset limits between the new pipeline and an existing pipeline, except at platform approaches, shall be as follows:

Approved:2009

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RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

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Chapter 2: Pipeline Design

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•

Minimum offset of new pipeline from nearest existing pipeline: 15m

•

Maximum offset of new pipeline from nearest existing pipeline: 50m

The maximum deviation from alignment along the prescribed route shall be ±15m except within 450m of the riser, where the maximum allowable deviation shall be as shown in Section 2.5.2. Where the pipeline is installed adjacent / parallel to an existing pipeline a minimum separation of 15m shall be maintained except at the platform approach. For pipelines installed by the Tow method, this deviation may be relaxed after consultation between the Pipeline Engineering Department, Marine Operations and where relevant, the installation contractor. 2.5.2

Platform Approaches At the approach to platforms the maximum allowable deviation from the prescribed route shall be reduced from that stated in Section 2.5.1 above as follows: •

From 450m of the riser to 150m from the riser : tapering from 15m to 3m

•

From 150m of the riser to the riser tie-in: 3m

At the pipeline to riser interface the deviation shall be sufficiently small so as to allow installation of the riser clamps without introducing bending stresses in the riser.

2.6

Geotechnical Site Investigation The objective of the site investigation for a marine pipeline is to obtain sufficient reliable information to permit the safe and economic design of installation and permanent works. The investigation shall be designed to verify and expand upon any information previously collected. The various stages relating to site survey and geotechnical investigation are illustrated in Figure 3. At the initial stages of a project development, it is often adequate to assess geotechnical aspects from desk study information. As the project progresses, the level of detail required increases and additional costs are incurred in acquiring this information. The important factor to appreciate is that at all times expenditure on the site survey and geotechnical data should be commensurate with the level of detail required.

Approved:2009

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Chapter 2: Pipeline Design

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FIGURE 3: GEOTECHNICAL DESIGN PHASE

2.6.1

Planning At project conception, the data available shall be sufficient to demonstrate the feasibility and suitability of the preferred pipeline design concepts and selected route corridors. This can often be achieved by a desk study to collate published data and information from previous investigations. However in areas where little information is available a preliminary investigation is required. This can often be achieved by a geophysical survey, with simple sampling methods such as a grab sampler, or drop corer. As the project progresses towards detailed design and construction, the data shall be sufficiently detailed to provide input into pipeline design and to allow contractors to provide optimised pricing for supply and installation works. The site investigation programme for a marine pipeline development shall therefore be undertaken in progressive stages. Planning for each stage shall be carried out based on the results from previous findings in order to optimise the extent of investigation work. Factors such as: vertical and horizontal uniformity of soil profiles, geological history and pipeline system size and concept, shall be directly reflected in the extent of the site investigation. A full appraisal of the various geological factors at a site shall be summarised in a geo-hazard study. It is recommended that all stages of the planning and performance of a survey are directed by a suitably experienced person. The sequence of the site investigation programme shall be as follows:

Approved:2009

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Chapter 2: Pipeline Design

Revision: 00

Desk study The desk study shall incorporate a review of all appropriate sources of information and the collection and evaluation of all relevant available types of data for the area of interest. The various factors that should be investigated include, but are not limited to: •

Geological databases

•

Bathymetric information

•

Geophysical data

•

Geotechnical data

•

Metocean data (tides, currents etc)

•

Seismicity

•

Performance of existing pipelines

•

Human activities (eg location of pipelines, cables wrecks, munitions disposal site, aggregate dredging

The performance of a desk study alone is not normally sufficient for detailed engineering purposes. The desk study is the best way of obtaining some information, including location of existing subsea infrastructure (e.g. pipelines and cables) which may be required for the planning of both the survey and the construction works. Geophysical survey A geophysical survey will need to be performed along the proposed route of the marine pipeline to collect information on: •

Seabed topography – by echo-sounding or swathe bathymetry. The latter is particularly important in sand wave areas or other areas of generally uneven seabed.

•

Seabed features and obstructions – by methods such as side scan sonar

•

Profiling of uppermost 5m, or so, of seabed – usually by means of reflection seismic techniques (sub bottom profiling). Recent developments in towed resistivity and seismic refraction methods are providing useful complementary data. This is particularly the case in very shallow water where seismic reflection is not practical.

•

Detection of existing cables, pipelines and other metallic obstructions – by means of a towed magnetometer, however, note is made that not all metallic objects may be detected, in particular small fibre optic cables.

As a general rule, the width of the survey corridor is between 500m and 1000m, centred on the proposed pipeline route. The actual width is influenced by factors such as water depth, seabed features and the need to provide a degree of flexibility in routing. Shore approach corridors are more likely to be around 500 metres wide, whereas areas in deeper water incorporating seabed features such as pockmarks and iceberg scars may warrant survey corridors in excess of 1000 metres to allow re-routing based on detailed engineering, to minimise the number of potential free-spans. If the geotechnical survey is to be performed as a separate exercise (see below) it is still advisable and practical to collect

Approved:2009

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Chapter 2: Pipeline Design

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some soil samples by grab or gravity core to aid the immediate interpretation of surface and sub-bottom profiling data. Survey tie-lines to nearby locations where soils information has previously been gathered will also aid this process. The geotechnical investigation will normally be performed on completion of the geophysical survey, and after the route has been determined, either from the same vessel or as a completely separate operation from a different vessel. This allows for sample and test locations to be more effectively targeted to identify soil strata changes, clarify apparent anomalies or investigate specific seabed features. To accelerate interpretation and reporting on long route surveys, a “first pass” of sampling and testing shall be made on completion of the route centre-line survey. Again, this may be performed from the geophysical survey vessel itself or from a separate vessel. In the latter case, the geotechnical vessel can be performing work along the centre line whilst the corridor “winglines” are being surveyed. Using current satellite technology it is now feasible to transmit interpreted data between the geotechnical and geophysical vessels to facilitate onboard interpretation and programme modifications as appropriate. The performance of the geophysical survey alone, or in addition to the desk study, is not normally sufficient for detailed engineering purposes, unless site geotechnical data are already available. GeoBAS survey The term ‘geoBAS’ (Geophysical Burial Assessment Survey) describes survey operations using geophysical methods operated from seabed sleds, and towed by the survey ship, to provide continuous quantitative information for the first few metres of soil below seabed. Available methods include seismic refraction and electrical resistivity systems. The use of these methods is often justified if trenching is difficult or the properties of the seabed are very variable. A more reliable continuous engineering assessment of the route can be made if GeoBAS measurements are integrated with CPT and core sample data. GeoBAS equipment is normally mounted on a sled, which is pulled by the survey vessel at speeds of between 1 and 4knots. It is essential to have some knowledge of seabed features and potential obstructions to reduce the risk of damage or loss of the equipment. GeoBAS surveys may also be useful on the shore approach where deeper burial is required and sometimes rock is present near the surface. Towed systems can be pulled through the shallow water zone either towards or away from the beach. Technical issues relating to shallow water and surf noise should be addressed in a project specific manner. Geotechnical survey The geotechnical survey will typically encompass: •

Coring and sampling for material identification, description and subsequent laboratory testing.

•

In situ testing for accurate stratification and determination of key engineering parameters.

Approved:2009

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The suitability of each tool for use in the geotechnical survey shall be assessed. This should be carried out in conjunction with knowledge of the engineering objectives of the selected concept(s) and the results of the desk study and geophysical survey phases.

2.7

Materials

2.7.1

Carbon Steel Linepipe for pipelines is ordered according to API Spec. 5L for material grades from B to X70, supplemented by VIETSOVPETRO’s specification. High Strength Butt-Weld Fittings for pipelines are ordered to MSS-SP-75 for material grades WPHY 42 to WPHY 70, supplemented by VIETSOVPETRO’s specification. High Strength Flanges for pipelines are ordered to ASTM A694 for material grades F42 to F70. Basic carbon steel properties are: •

Density = 7850 kg/m3

•

Modulus of elasticity = 2.05 x 105 MPa

•

Thermal expansion coefficient = 1.17 x 10-5 °C-1

•

Poisson's ratio = 0.3

Other mechanical properties reported by the pipe mill are: •

Yield strength

•

Ultimate tensile strength

•

Elongation

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•

Reduction in area

•

Fracture toughness

•

Hardness of welded joints

•

Hydrogen induced cracking resistance

Tests and acceptance criteria for these properties are covered in the above specifications. The grade of the material is determined by the Specified Minimum Yield Strength (SMYS) expressed in thousands of psi (X-42 = 42,000 psi). Metric values for SMYS are: API Spec. 5L

SMYS

SMTS

Grade for Linepipe

(MPa)

(MPa)

Butt-Weld Fittings

Flanges

B

241

413

ASTM A234 WPB

ASTM A105

X42

289

413

MSS-SP-75 WPHY 42

ASTM A694 F42

X52

358

455

MSS-SP-75 WPHY 52

ASTM A694 F52

X60

413

517

MSS-SP-75 WPHY 60

ASTM-A694 F60

X65

448

530

MSS-SP-75 WPHY 65

ASTM-A694 F65

X70

482

565

MSS-SP-75 WPHY 70

ASTM A694 F70

Equivalent Strength Materials

Offshore pipelines are usually constructed in material Grades X42 and X52. Many onshore pipelines may be constructed from Grade B material. For new and future carbon steel pipelines the material grade is set as follows: •

For linepipe of up to 12" Nominal Diameter (DN300) X52 grade

•

For linepipe of 12" and greater Nominal Diameter (DN300) X60 grade

In general, linepipe of DN300 (Nominal Diameter in mm) and smaller shall be seamless manufacture. HF-ERW (High-Frequency Electric Resistance Welded) pipe may also be used for diameters up to and including DN 600. Note that for pipelines (refer ASME B31.4 and B31.8) a weld joint factor of 1.0 may be applied for ERW pipe, but for piping (refer ASME B31.3) a factor of less than 1.0 is applied. For DN400 and greater SAW (Submerged Arc Welded) pipe may be used. 2.7.2

Glass Reinforced Plastic Glass Reinforced Plastic (GRP) pipelines usually have been used for flowlines, water mains (onshore) and water piping (offshore). GRP is advantageous for the transport of corrosive products. In addition the friction factor for fluid flow can be substantially below steel and the life for GRP piping is usually significantly longer than that experienced with steel. Unlike steel, GRP pipe can come in a wide range of material specifications for different applications. Careful selection is thus required.

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The means of connection of pipe joints is either mechanical or adhesive. The application of GRP should be considered for all future pipelines transporting corrosive fluids on a performance and life cycle cost basis. 2.7.3

Corrosion Resistant Alloys For very corrosive service, the application of corrosion resistant alloys, such as stainless steel or carbon steel with an internal cladding, shall be considered. Before designing a corrosion resistant alloy, VIETSOVPETRO JV should be consulted.

2.7.4

Plastics For the transport of domestic gas and water, pipes made from polymer compounds have found world-wide acceptance. Some of the referred materials are: HDPE

High Density Polyethylene

MDPE

Medium Density Polyethylene

UHMW-HDPE

Ultra High Molecular Weight

PVC

Polyvinyl chloride

All have different properties and manufacturers’ catalogues should be consulted. For high pressure applications, Polyethylene (PE) lined steel pipe could be considered. The PE liner provides the corrosion-resistant fluid barrier, whilst the steel carrier provides the strength (Ref. 54). 2.7.5

Flexibles Flexible pipelines have found use in many other parts of the world particularly in deeper waters. Materials used in the carcass construction allow flexible pipelines to be corrosion resistant (Ref. 53). Flexible pipelines are expensive and their application can usually only be justified for repairs on damaged pipelines, risers, jumper hoses, or short pipeline runs.

2.8

Leak Detection and Isolation Systems Many of pipelines are equipped with a low pressure sensor on the inlet, for closing the inlet valve. The low pressure sensor can usually only detect full bore ruptures, relatively close to the inlet. Some pipelines have a high flow sensor in addition to the low pressure sensor. This system allows smaller than full bore ruptures to be detected along the whole line. Pipelines must have an integrity monitoring system capable of detecting leak. A leak detection system in itself has no effect on the leak expectancy of a pipeline and will only make the operator aware of the occurrence of a leak, enabling him to take remedial actions in order to limit the consequences of the release. The leak detection system requirements will vary depending on the pipeline system in question (e.g. offshore or onshore, length etc.) however, the following should be considered at the design stage and/or implemented during operation.

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On-Line Leak Detection • • • • • • •

continuous mass balance of the pipeline; continuous volumetric balance corrected for temperature and pressure of the pipeline; continuous monitoring of rate of change of pressure; continuous monitoring of rate of change of flow; low pressure alarms; high pressure alarms; high flow alarms;

Off-Line Leak Detection • • • • • • • 2.9 2.9.1

visual inspection of the pipeline route; running of a leak detection pig (see Chapter18.3.3); methane-in-water sensing by Remotely Operated Vehicle (ROV). Several other methods of on-line leak detection are available, some of which will also indicate the location of a suspected leak. However, in general a good deal of intermediate pressure, temperature and flow information is required with attendant telemetry and for this reason such methods are not generally suitable for offshore use.

Diameter Selection Basics Unless otherwise stated, pipe diameters refer to the outside pipe diameters. Nominal pipe sizes (NPS) are quoted in inches. These are the actual outside diameters in sizes of NPS 14 and beyond. Up to NPS 12, the diameters are not exact. For example NPS 4 has an outside diameter of 4.5 inches. Nominal Diameters (DN) are quoted in mm. These are never the exact outside diameters but a metric approximation to them. Standard diameters and wall thicknesses for steel linepipe are listed in API-5L (Ref. 20). It is generally good practice for short lines to choose the next standard pipe size above the exact requirement.

2.9.2

General Considerations The first consideration in selecting a pipeline diameter is that it provides acceptable pressure drop for the maximum anticipated flow rates. The second consideration is the cost trade-off between new pumps / compressors and new pipelines. Other factors which are important in the selection of the pipe diameter are as follows: Throughput The forecast over the life of the pipeline should be as accurate as possible, with reasonable allowances for unforeseen increases. To accommodate a high peak of relatively short

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duration it might be more economical to increase the design pressure than to install a pipeline designed for that peak throughput at a lower pressure. In the case of a gradual increase in throughput over the life of the pipeline or a sudden increase at a later date, the possibility of installing a second pipeline at some time during the life of the first should be considered, as this may prove to be more economical and operationally attractive. Fluid properties Main properties are specific gravity, operating temperatures, viscosity and / or composition. Operating pressure The selection of operating pressure is dependent on available or required inlet pressure, required discharge pressure, pressure rating of connecting facilities, pipe size and pipe materials; and therefore in turn influences the selection of pipe dimensions. Operating pressure can also heavily influence corrosion rates with high CO2 content. Source and cost of pumping/compression energy Capital investment and operating cost that are required for increasing the inlet pressure will also influence the overall economics. Available construction methods Depending on the conditions at the intended location such as weather conditions, current velocity, wave heights, tidal effects, bottom conditions, water depth, etc., there may be a preference for one of the possible construction methods which in turn could put certain limitations on the selection of line sizes. The available or preferential construction method also may limit the selection of pipe wall thickness and grade and the type of coating. Future Use The function of a pipeline may change over the years. Future uses should be anticipated in the design phase, and incorporated in the design where possible. 2.9.3

Velocity Limitations When high water dropouts might be expected in oil lines it is advised to design for a minimum velocity of 1.5 m/s. Velocities in wet and two phase gas lines should be high enough avoid slugging problems, typically more than 3 m/s. Erosion of the pipeline wall due to impingement of high-velocity liquids or gases might occur, particular in flowlines and at bends. The equation commonly used to assess the potential for erosion is (Ref. 24):

⎛ 1 Ve = 122 ⎜⎜ ⎝ ρm Approved:2009

⎞ ⎟⎟ ⎠ Page 21 of 72

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where:

Ve

=

erosional velocity, [m/s]

ρm

=

mean fluid density, [kg/m ]

3

This equation gives a lower bound to potential erosional problems. Velocities in excess of Ve, may still be acceptable. In those cases VIETSOVPETRO JV should be consulted for further analysis. Velocities below Ve are safe. 2.9.4

Recommended Standard Operating Pressures Related with the separation stages at the production facilities the following pressure classes can be distinguished:

Operating Pressure regime

Nomenclature

ANSI class

(kPa)

Maximum Pressure (below 38 °C) (kPa)

UHP (Ultra High Pressure)

12,500 to 17,000

#1500

25,500

HHP (High High Pressure)

5,500 to 7,000

#600

10,200

IP (Intermediate Pressure)

4,000 to 4,200

#300

5,100

HP (High Pressure)

1,400 to 2,100

#300

5,100

LP (Low Pressure)

300 to 650

#150

1,965

The ANSI classification is only relevant to any fittings (flanges, valves, etc.) which may be included in a pipeline. These can be the "weak points" in a pipeline design. For the pipeline it is good practice to determine a design pressure based on the anticipated maximum operating pressure plus a 10 % margin. 2.9.5

Sizing Criteria for Liquid Lines In single phase liquid pipelines the fluid properties remain essentially constant over the entire length of the pipeline unless there is a significant temperature change. The general equation for the pressure drop in a liquid pipeline is as follows:

Δ P = ρgΔz + ρf

Approved:2009

Lv 2 2d

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where:

ΔP

=

pressure drop, [Pa]

ρ

=

density of liquid, [kg/m ]

Δz

=

elevation change (positive upwards) [m]

g

=

acceleration due to gravity [m/s2]

f

=

Moody friction factor

L

=

pipeline length [m]

v

=

liquid velocity [m/s]

d

=

internal pipe diameter [m]

3

The fluid velocity “v” may be determined from the volumetric flow rate by:

v= where :

4Q πd 2

Q = volumetric flow rate (m3/s) To determine the friction factor “f” the Reynolds number “Re” has to be calculated from:

Re =

vd

υ

where:

v

=

flow velocity [m/s]

υ

=

kinematic viscosity [m2/s]

The friction factor “f” can be read from the standard Moody diagram with a suitable value of relative roughness ε/d. Typical values of pipe wall roughness ε are: Plastic coated

0.01 mm

Clean steel

0.02 mm

Corroded steel

0.1 to 1 mm

Concrete

0.2 to 1 mm

For the design of new or non corrosive pipelines, a roughness value of 0.045 mm is often used. For detailed analysis it is recommended to use the PIPESIM correlations. Approved:2009

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Sizing Criteria for Gas Lines For level gas lines, containing no liquid, the AGA equation can be used for initial sizing.

Pi 2 − Po2 Q2 = CfzT ρ − 5 L d where:

Pi

=

inlet pressure [MPa]

Po

=

outlet pressure [MPa]

C

=

5.7 x 10-10 [MPa/K]

z

=

compressibility factor

ρ

=

gas density at 101 kPa and 15 °C [kg/m3]

T

=

Temperature

For final sizing, it is recommended to use the PIPESIM correlations, using either the "black oil" model or preferably the compositional model. 2.9.7

Sizing Criteria for Two-Phase Lines There are numerous correlations for pressure drop / flow / diameter / flow regime determination for two-phase flow. None is easy to apply without computer assistance. It is recommended that for all two-phase (and so-called three-phase) calculations the PIPESIM correlations are used.

2.9.8

Pressure Losses in Valves and Fittings Pressure losses in valves and fittings are usually determined on the basis of an equivalent length of pipe following the table below. Valve Type Globe valve (conventional) Globe valve (Y-type design) Globe valve (angle type - 90o) Ball valve (spherical plug valve) Check valve

Approved:2009

Feature No obstruction With wing-guided disc Stem 60o from pipe run Stem 45o from pipe run No obstruction With wing-guided disc Full bore Reduced bore (< 40 mm) Reduced bore (> 40 mm) Conventional type In-line ball type Globe lift ball type Angle lift ball type

Equivalent Length 340 D 450 D 175 D 145 D 145 D 200 D 3D 65 D 45 D 135 D 150 D 340 D 145 D Page 24 of 72

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Valve Type Gate valve

Equal-tee Elbow Bend Nozzle

Feature Conventional type Reduced bore Conduit pipeline Flow straight-through Flow through side 90°, R=1.5 D 45°, R=1.5 D 90o, R= 5 D 180o, R= 5 D Suction nozzle on tank Outlet nozzle on tank

Equivalent Length 13 D 65 D 3D 18 D 65 D 20 D 16 D 16 D 28 D 32 D 64 D

2.10 Wall Thickness Selection 2.10.1 Basics The pipe wall thickness is determined primarily on pressure containment requirements as defined in the ASME B31.4 or B31.8 codes. Standard wall thicknesses are given in API Spec. 5L. By attempts to restrict the range of wall thicknesses in any one size in order to limit the material stocks provided the cost penalty is small. Pipe schedules are a series of numbers which identify a range of standard pipe wall thickness and are used for on-plot pipework, designed in accordance with ANSI/ASME B31.3 only. Definitions: Design pressure is to be taken as the MOP or the pressure class of the connected piping system, whichever is greater. Maximum operating pressure is the highest pressure at which a piping system is operated during a normal operating cycle, abbreviated as MOP. (Sometimes referred to as maximum actual operating pressure.) Maximum allowable operating pressure is the maximum pressure at which a pipeline system may be operated in accordance with the provisions of the design code, abbreviated as MAOP. 2.10.2 General Considerations The wall thickness selection is primarily based on the hoop stress criteria, as specified in the ASME B31.4 and B31.8 codes. The ASME B31.4 code basically applies to liquid lines and the ASME B31.8 code to gas and two-phase lines. For details refer to the relevant codes.

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A corrosion allowance is only added to the minimum required wall, if the service conditions are corrosive. Additional wall thickness may be required to:

•

withstand installation stresses,

•

ensure on-bottom stability,

•

provide additional pressure safety in certain areas (e.g. risers),

•

ease the welding requirements,

•

provide increased resistance against collapse.

The pipe wall thicknesses should provide an adequate allowable operating pressure under the applicable codes and this Guideline. The internal design pressure should not be less than the maximum steady state operating pressure. If levels of pressure rise due to surges (and other variations from normal operations) exceed the internal design pressure by more than 10%, protective equipment should be provided. 2.10.3 Hoop Stress Sizing Criterion The required wall thickness can be based on the following hoop stress criterion:

t=

pD 2σ y fET

where:

t

=

nominal wall thickness [m]

p

=

design pressure [MPa]

σy

=

specified minimum yield strength [MPa]

E

=

weld joint factor (usually = 1)

T

=

temperature de-rating factor (< 120oC T = 1)

f

=

design factor

D

=

outside diameter of pipe [m]

For offshore pipelines, the ASME B31.8 code specifies for the hoop stress design factors:

Approved:2009

f

=

0.72 for pipeline in Zone 1

f

=

0.50 for riser and pipeline within Zone 2

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The ASME B31.4 code (liquid lines) specifies for onshore lines a design factor of 0.72 throughout; however this has been modified for certain locations, for application here. The ASME B31.8 code (gas/liquid lines) specifies for onshore lines according to zones. Refer to Table 1 in Section 2.13.2. Particularly for offshore pipelines and risers, a detailed stress analysis should be carried-out taking into account all load conditions (thermal, environmental, bending) and all stress components (axial, hoop, shear). 2.10.4 Code Transition Pigging facilities (launchers and receivers) are designed in accordance with the pipeline codes and are generally installed on the scraper deck of a platform. In view of pig / sphere runs through pipelines, great differences of internal diameter (steps) cannot be tolerated. The transition of code from pipeline (ASME B31.4/8) to piping (ASME B31.3) should therefore be at the valves connected to the barrel and tee (see Figures 5 and 6). There are numerous examples of scraper barrels and/or riser connecting pipework which have been designed according to ASME B31.3 (specification break at the riser insulation flange). This situation should be corrected on a maintenance opportunity basis, provided the incremental costs are small.

FIGURE 5: TRANSITION CODE FOR PIPING AND PIPELINE

Approved:2009

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FIGURE 6: TRANSITION CODE FOR PIPING AND PIPELINE

2.10.5 Pipe Wall Thickness Tolerances The steel wall thickness should not deviate from the nominal thickness by more than +10% or -5% for all sizes of welded pipe. Furthermore, below a nominal wall thickness of 7 mm the acceptable minus tolerance is -0.35 mm and above 10 mm wall thickness the maximum acceptable minus tolerance is -0.5 mm. For all sizes of seamless pipe, the wall thickness should not deviate from the nominal thickness by more than +15% or -10%. 2.10.6 Minimum Nominal Pipe Wall Thickness The wall thickness which will facilitate high quality welds, coating and construction, should not be less than the following minima: Pipe diameter

Minimum wall thickness

DN100 to DN200

4.0 mm (0.156")

DN250 to DN300

4.8 mm (0.188")

DN400 and larger

6.4 mm (0.250")

Approved:2009

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2.11 Standardisation of Linepipe To rationalise the amount and variety of pipe held in stock and to simplify handling provisions, VSP may standardise on one wall thickness and material grade per pipe diameter for short lines. In addition some sizes of pipe may not be used. The table below gives the recommended pipe sizes, wall thickness and grades of material. Non-conformance of new pipelines with values in this list should only be considered if the additional capital expenditure can be justified against the costs of stocking non-standard pipeline joints for repair purposes. DN

Outside Diameter mm (inches)

Material Grade API Spec. 5L

Wall thickness [mm]

MAOP [MPa] f=0.72

100

114.3 (4.5)

X-52

8.6

38.8

150

168.3 (6.625)

X-52

9.5

29.1

200

219.1 (8.625)

X-52

9.5

22.4

250

273.1 (10.75)

X-52

9.3

17.6

300

323.9 (12.75)

X-60

9.5

17.5

400

406.4 (16)

X-60

10.3

15.1

500

508.0 (20)

X-60

11.1

13.0

600

609.6 (24)

X-60

12.7

12.4

700

711.0 (28)

X-60

12.7

10.6

DN

Outside Diameter

Material Grade

Wall thickness

References

mm (inches)

(VSP ref.)

[mm]

200

219.1 (8.625)

X-60

12.7

Gaslift pipeline

250

273.1 (10.75)

X-60

18.3

Water Injection pipeline

300

323.9 (12.75)

X-60

15.9

Oil/mix/gas pipeline

350

273.1 (10.75)

X-60

23.8

Water Injection pipeline

2.12 Environmental Data 2.12.1 Waves As a minimum, the following wave data shall be available at suitable locations along the route:

Approved:2009

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•

Significant wave heights (Hs) and spectral peak periods (Tp) for 1 year and 100 year return period storms.

•

Maximum wave heights (Hmax) and associated periods (Tmax) for 1 year and 100 year return period storms.

For overall pipeline stability assessment, the significant wave height and spectral peak period shall-be used to calculate wave induced flow velocities. For-riser design, and for localised pipeline sections such as spans and crossings, the maximum wave height and associated period shall be used. For each combination of water depth and wave parameters, a suitable wave theory for predicting water particle motions shall be adopted. At locations of relatively shallow water depth and near shore areas, shoaling and refraction effects shall be evaluated including the effects of bottom friction on wave height, sediment transport and other effects. If a shoaling and refraction analysis is not considered necessary, suitable justification shall be provided The design wave used for concept of the design of offshore jackets in which the most probable is maximum wave in a period of 100 years which is replaced by a regular wave of a suitable wave length, period and steepness. To determine the wave-induced water particle velocity at any water depth VIETSOVPETRO JV could be consulted. They will select a suitable wave theory and from user supplied data will calculate:

•

Wave length, wave celerity, depth of wave influence and wave profile.

•

Components of wave particle velocities and accelerations at standard grid points in a periodic wave.

As an approximate alternative, the linear wave theory may be applied. First the wavelength needs to be estimated. The controlling equation is:

gT 2 ⎛ 2π d ⎞ tanh ⎜ L= ⎟ 2π ⎝ L ⎠ where:

L

=

Wavelength [m]

g

=

Gravitational acceleration [m/s2]

T

=

wave period [s]

d

=

water depth [m]

Note that this equation is implicit in L and therefore requires an iterative solution. A good starting point is to assume a deep water wavelength, i.e.:

Approved:2009

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gT 2 L= 2π and substitute in the right hand side to find a new value of L. Repeat until convergence, which is usually rapid. For conditions in which d / L > 0.1 the maximum horizontal water particle velocity may be determined from:

uw =

π H cosh⎛⎜ 2π

( d−y) / L ⎞

⎝ T sinh(2π/L )

⎟ ⎠

where:

uw

=

wave induced velocity at depth y, [m/s]

H

=

wave height, [m]

y

=

depth below surface (positive), [m]

For pipeline on-bottom stability calculations:

y=d−D where:

d

=

water depth, [m]

D

=

total outside diameter of pipe (including coatings) [m]

For conditions in which d / L < 0.1, such as the foreshore area, linear wave theory is not applicable. In this region solitary wave theory should be applied. The design practice for on-bottom stability of pipelines is to consider the significant wave height. For riser design the maximum wave height data for a 100 year return period should be used, which is the same approach as taken for all jacket tubular. For maintenance and operational related assessment of risers the significant wave height data should be used, with a 10 year return period and similarly for installation, a 1 year return period. 2.12.2 Currents Design 'steady' current data will be provided in the form of directional for 1 year and 100 year return periods. As a minimum, a surface and near bottom velocity shall be provided, including tidal, surge, and wind driven components. If an accurate profile is not available, the design current at any depth shall be calculated from the available data in accordance with the 1/7th power law: Approved:2009

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RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

⎛D⎞ uc =u s ⎜ ⎟ ⎝d⎠

1/ 7

where:

uc

=

current velocity one pipe diameter above the seabed [m/s]

us

=

surface current velocity [m/s]

D

=

total diameter of pipe (including coating) [m]

d

=

water depth [m]

For a pipeline resting on the seabed boundary layer effects are significant and an 'effective" (mean) current velocity acting on the pipeline shall be calculated. This may be taken as the integral of the square of the velocity from the seabed to the top of the pipe. An alternative, conservative approximation is to use the current velocity at the top of the pipe in hydrodynamic force calculations. 2.12.3 Water Depth At a given location, the most critical (either maximum or minimum) water depth should be used as appropriate in each design analysis. For example, minimum water depth (LAT) shall be used for pipeline on-bottom stability and in-situ stress analyses. The relevant storm surge may, however, be added to the water depth in such cases. Maximum water depth (HAT) shall be used for pipeline buckling, collapse and installation stress analyses. For buckling and collapse analyses, surface wave heights shall also be included. For riser stress analyses, both maximum and minimum depths shall be considered, as either may prove critical. Unless specified otherwise, the-following sea water parameters may be used:

•

Density of sea water 1025 kg/m3

•

Kinematic viscosity of sea water

0.96 x 10-6 m2/s (25 deg. C) 0.85 x 10-5 m2/s (35 deg. C)

2.12.4 Ambient Temperatures The sea temperatures in absence of other data shall be the following:

•

Average sea temperature = 21 °C (on surface)

•

Average sea temperature = 15 °C (on bottom)

Approved:2009

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

2.12.5 Operating Temperatures The maximum product temperature from an oil well is unlikely to exceed 50°C but note that material limitations are imposed at temperatures in excess of 38°C for certain components. New wells, however, tend to have higher pressures and temperatures. 2.12.6 Marine Growth In the absence of more accurate data, the marine growth thickness for the riser assembly shall be assumed to be 90 mm at MSL. Marine growth decreases in thickness with increasing water depth. This thickness shall be assumed to decrease by 1 mm for every further 2 metres of water depth. Marine growth density may be assumed to be the same as for seawater. 2.13 Stresses and loads 2.13.1 General Pipelines and risers have to be designed against the following during all phases of installation and operation.

•

Yielding

•

Buckling

•

Fatigue

Loading which cause the generation of stresses in the pipe wall may be grouped as follows: a.

Functional Loads - Pressure (including burial pressure) - Self weight (or buoyancy) - Thermal loads

b.

Environmental Loads - Wind - Currents - Waves - Accidental loads (including anchors)

The loading generate combinations of hoop, bending and longitudinal (axial) stresses. These stresses are usually combined using the von Mises criterion. 2.13.2 Stresses The pipeline wall thickness selection is usually governed by the hoop stress criterion (see section 2.10.3). The hoop stress is directly related to the internal design pressure of the line:

σh = Approved:2009

PD 2t Page 33 of 72

JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

where:

t

=

wall thickness [m]

P

=

internal pressure [MPa]

σh

=

hoop stress [MPa]

D

=

steel pipe outer diameter [m]

Hoop stresses and longitudinal stresses (including the maximum bending stresses) in pipe material are combined using the von Mises criterion, as follows.

(

σ eq = σ h 2 +σ L 2 −σ hσ L +3τ 2

)

where:

σ eq

=

equivalent stress [MPa]

σh

=

hoop stress [MPa]

σL

=

longitudinal stress [MPa]

τ

=

combined shear stress [MPa]

Note: Longitudinal stress is due to pressure, thermal expansion and bending) Note: the equivalent stress is maximised when one stress is compressive (typically the longitudinal stress) and the other is tensile (typically the hoop stress). Tensile stresses are generally assumed to be positive, compressive stresses negative. The specified minimum yield stress (SMYS) is generally defined as the stress level at 0.5 % strain, during a tensile test. The stress calculations for the operational phase shall be carried out with the nominal wall thickness excluding the corrosion allowance. For pipelines operating above 60°C, consideration shall be given to switch from a stress based design to a strain based design. In such cases, guidance and approval shall be sought from the VIETSOVPETRO JV (see also 2.13.3). TABLE 1 - DESIGN FACTORS FOR ONSHORE STEEL PIPELINES FLUID CATEGORY ⇒ APPLICABLE CODE ⇒

A and B

C and D

(Note 1)

(Note 1)

B31.4

B31.8

(Note 2)

LOCATION CLASSES ⇒ Pipelines Crossings (Note 3) : Private roads Approved:2009

1, 2, 3 and 4 0.72

1 0.72

2 0.60

3 0.50

4 0.40

0.72

0.72

0.60

0.50

0.40

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

Unimproved public roads Roads, highways, streets and railways Rivers, dunes and beaches Parallel encroachments (Note 4) : Private roads Unimproved public roads Roads, highways, streets and railways Fabricated assemblies (Note 5) : Pipelines on bridges Near concentration of people Pipelines, within plant fences, block valve stations and pig trap stations (Note 7)

0.60 0.60

0.60 0.60

0.60 0.60

0.50 0.50

0.40 0.40

0.60

0.60

0.60

0.50

0.40

0.72 0.72 0.72

0.72 0.60 0.60

0.60 0.60 0.60

0.50 0.50 0.50

0.40 0.40 0.40

0.60

0.60

0.60

0.50

0.40

0.50 0.50

0.40 0.40

0.50

0.5

0.60 0.72 0.60

0.60 0.60 0.50 0.50 (Note 6) (Note 6) 0.60 0.60

NOTES: 1. The fluid transported in the pipeline should be categorised in one of the following four groups, depending on its hazard potential: •

Category A: Non-flammable, stable and non-toxic fluids which are liquid at prevailing ambient temperature and atmospheric pressure plus 0.5 bar, i.e. the vapour pressure is lower than 1.5 bar (abs) at ambient temperature. Example: water, slurries.

•

Category B: Flammable, or unstable or toxic fluids which are liquid at prevailing ambient temperature and atmospheric pressure plus 0.5 bar, i.e. the vapour pressure is lower than 1.5 bar (abs) at ambient temperature. Example: stabilised crude, gasoil.

•

Category C: Non-flammable, stable and non-toxic fluids which are gases or a mixture of gas and liquid at prevailing ambient temperature and atmospheric pressure plus 0.5 bar, i.e. the vapour pressure is higher than 1.5 bar (abs) at ambient temperature. Example: nitrogen, carbon dioxide

•

Category D: Flammable, or unstable or toxic fluids which are gases or a mixture of gas and liquid at prevailing ambient temperature and atmospheric pressure plus 0.5 bar, i.e. the vapour pressure is higher than 1.5 bar (abs) at ambient temperature. Example: natural gas, liquid petroleum gas, ammonia, unstabilised crude, hydrogen sulphide.

2. ASME B31.4 does not use design factors other than 0.72, which is considered inappropriate at critical locations (e.g. crossings, within plant fences), and for fabricated assemblies. In these situations, design factors in line with ASME B31.8 location Class 1 are recommended. 3. ASME B31.8 differentiates crossings with casings and without casings. Because of the poor experience of cased crossings (i.e. annular corrosion), the same design factor is recommended, whether a casing is used or not. Design factors for crossings of rivers, dunes and beaches, not included in ASME B31.8, are provided. 4. Parallel encroachments are defined as those sections of a pipeline running parallel to existing roads or railways, at a distance less than 50 metres. 5. Fabricated assemblies include pig traps, valve stations, headers, finger type slugcatchers, etc. 6. Concentrations of people are defined in ASME B31.8 Article 840.3. 7. This category, not specifically covered in ASME B31.8, is added for increased safety. Approved:2009

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Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

TABLE 2 - DESIGN FACTORS FOR OFFSHORE PIPELINES DESIGN CONDITION

LOADING CONDITION

Operating

Functional

Operating

Functional plus Environmental

Installation

Functional

Installation Hydrostatic test

Functional plus Environmental Functional plus Environmental

STRESS CLASSIFICATION Hoop Stress von Mises Equivalent Stress Hoop Stress von Mises Equivalent Stress von Mises Equivalent Stress von Mises Equivalent Stress

ALLOWABLE STRESS ZONE 1 ZONE 2 0.72 0.72

0.50 0.50

0.72 0.96

0.50 0.67

0.72 (refer Notes 1 to 4)

0.96 (refer Notes 1 to 3)

Hoop Stress von Mises Equivalent Stress

0.90 1.0

NOTE 1. For the purpose of this Guide the definition of Zones shall be as follows: For lines considered to be critical and for lines to or from manned facilities, Zone 2 shall extend 500m outwards from the bottom bend of the riser at the seabed. For lines considered to be non-critical and for lines to or from not normally manned facilities, Zone 2 shall extend 50m from the bottom bend of the riser at the seabed, and shall include the expansion spool where present. For landfall areas Zone 2 shall be taken as extending from LAT to 500m offshore. Zone 1 shall be taken as all areas outside of Zone 2. For short in-field lines (typically, less than 2km) it may be more economical to classify the entire line under Zone 2. 2. The specified allowable stresses during installation are not applicable to installation methods where yielding of the pipe wall is an integral part of the method (e.g. reeling, bending shoe, J-tube pull). For such methods, refer to (2.13.3). 3. During installation, a factor of 0.85 may be applied to the bending stress in the equivalent stress calculation in accordance with the DNV 1981 Rules, paragraph 4.3.2.6. 4. For the standard S-lay method of pipeline installation, the allowable equivalent stress in the overbend (supported on the barge ramp/stinger) may be increased to 96% of SMYS under functional loading conditions.

2.13.3 Strain based design During pipeline construction where yielding of the pipe is an integral part of the method, it is sometimes more appropriate to apply limitations to the maximum allowable strain of the pipe wall rather than to a maximum allowable stress. Examples are offshore pipeline installation by reeling, and riser installation by J-tube pull or bending shoe. When the pipeline is plastically deformed, it shall be demonstrated that, after straining, the pipeline material still complies with the required specifications; this is particularly relevant to toughness, hardness and yield to tensile ratio properties. In such cases, maximum Approved:2009

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RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

allowable strains shall be as defined in paragraphs of sec. 5 C600, sec. 6 A300 and sec. 9 E100 of the DNV 1996 Rules. (See Reference 4). A maximum permanent bending strain of 2 percent resulting from installation is acceptable in general. The strain induced in a pipeline by bending it along a radius R is given by:

ε=

D 2R

where:

ε

=

bending strain in outer fibre

D

=

pipe outer diameter [m]

R

=

bending radius [m]

The induced bending stress is:

σ = Eε where:

σ

=

Bending stress [MPa]

E

=

Young's Modulus of elasticity [MPa]

NOTE: During installation and operation the maximum allowable stresses shall be in accordance with Table 2 of Section 2.13.2. For cold bending of linepipe the bending strain shall not exceed 2 %. In addition, the pure bending buckling criteria should be checked. This criterion defines the maximum allowable elastic curvature. The corresponding minimum allowable elastic bend radius is given by:

Rmin =

1 −

k

where:

Rmin =

D2 = t

Minimum bend radius [m]

−

k

=

Critical curvature for elastic bending [1/m]

D

=

pipe outside diameter [m]

t

=

pipe wall thickness, [m]

The design of pipelines for service at elevated temperatures, the equivalent stress requirements (2.13.2) may in some situations lead to very high wall thicknesses. Such pipelines may hence also require a strain-based design approach to allow for efficient design. This is particularly relevant to pipelines transporting hot products (typically above 80 °C). Approved:2009

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RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

For pipelines operating at temperatures above 100°C temperature de-rating factors should also be taken into account. This is particularly relevant to the use of Corrosion Resistant Alloy (CRA) materials. 2.13.4 Hydrostatic Pressure and Pipeline Collapse during Installation When a line is laid, it is empty and the external water pressure creates a compressive hoop stress, which could cause collapse of the pipe. An out-of-roundness in the pipe enhances the risk of collapse. At the locations where the calculated external pressure which would cause buckling is lower than the actual external pressure, the pipeline shall be fitted with buckle arrestors (typically every ten joints). For pipelines installed from a laybarge a minimum D/t (diameter to wall thickness) ratio of 60 should be used in order to avoid buckling during the laying procedure. Hydrostatic collapse is generally not a concern, in view of its shallow waters. For projects in deeper waters (typically > 100m) collapse may need to be taken into account. In any case, buckling and collapse calculations shall be performed for both the installation and operational conditions and the 'worst case' load conditions. Maximum water depth (HAT), inclusive of surface wave heights, shall be used for pipeline buckling and collapse analyses. The pipeline system shall have an adequate factor of safety against the following modes of failure during all design conditions:

•

Local buckling due to combined bending, external pressure and axial force

•

Propagation buckling

•

'Bar' buckling (Euler buckling)

•

Collapse (due to external overpressure)

Acceptance criteria for local buckling and 'bar' buckling modes shall be in accordance with Appendix A of the DNV 1996 Rules, as follows: For propagation buckling, the external overpressure required to initiate a propagating buckle, Pbi, may be determined from the following equation:

⎛ t ⎞ Pbi = 0.02 E ⎜ ⎟ ⎝D⎠

where:

2.064

E

=

Young's modulus of elasticity for steel

D

=

nominal outer diameter of pipe, [m]

t

=

minimum pipe wall thickness, [m]

t

=

nominal wall thickness minus the manufacturing tolerance

Note:

Approved:2009

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

Due to the economic consequences of a propagating buckle, a safety factor fb against the initiation of a propagating buckle shall be used. A recommended value for fb is 1.5, although other values may be agreed on a case by case basis. Buckle arrestors shall be installed where the external pressure, Pext ≥ Pbi /fb. Alternatively, for short pipelines, it may be more economical to increase the wall thickness to ensure that Pext ≥ Pbi /fb. Buckle arrestor spacing shall be based on an assessment of installation and repair costs, but should not exceed one every 10 pipe joints. The external overpressure necessary for an initiated buckle to propagate along the pipeline is less than Pbi and is given by:

⎛ t ⎞ Pbp = 24 S y ⎜ ⎟ ⎝D⎠

2 .4

where:

Sy

=

SMYS of the pipe steel (as per API Specification 5L)

However, if buckle arrestors are installed where Pext ≥ Pbi /fb, there is no need to install such arrestors where Pbp < Pext < Pbi /fb. The acceptance criteria for pipe collapse due to external pressure shall be that Pext > Pc, the critical collapse pressure. Pc shall be determined by the following equation: Critical collapse pressure, Pc =

g (r , d )Py Pe

(P

y

2

+ Pe

2

)

where:

⎛ t ⎞ ⎟ ⎝D⎠

Pure plastic collapse pressure, Py = 2 S y ⎜

2 E (t D )

3

Pure elastic collapse pressure, Pe =

With:

r=

Py Pe

and

(

)

1.4 1 − γ 2 (1 − t D )

2

( t)

d =δ D

δ=

(Dmax − Dmin ) (Dmax + Dmin )

Sensitivity of the above calculation shall be checked with methods laid down in DNV 1996 Rules. Approved:2009

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RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

2.13.5 Wave and current loads A pipeline resting on the seabed is subjected to forces resulting from steady currents and waves. These forces are:

•

Fd = drag force

•

FL = lift force

•

Fm = inertia force

In determining the maximum wave and current loads, the water particle velocities due to current and waves are assumed to be additive thus : u = uc + uw The distributed loading on a pipe or riser due to relative particle motion is determined using the Morison equation.

u 2

Fd = ρ D Cd where:

2

Fd

=

unit drag force acting normal to the pipe and in the plane defined by the velocity vector and the pipe axis [N/m]

ρ

=

mass density of surrounding liquid [kg/m ]

D

=

outer diameter of the pipe including coatings [m]

Cd

=

drag coefficient for flow normal to the pipe axis

u

=

fluid particle velocity normal to the pipe axis [m/s]

3

The drag coefficient depends upon a number of parameters including Reynolds number, the Keulegan-Carpenter number (for waves) and pipe roughness. The lift force per unit length for a pipe in close proximity to a fixed boundary (seabed) is calculated in similar fashion. 2

FL = ρ D CL where

F

L

C

L

Approved:2009

u 2

=

unit lift force acting normal to the pipe and normal to the velocity vector [N/m]

=

lift coefficient for flow normal to the pipe axis

Page 40 of 72

JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

The inertia forces exerted by accelerating water particles (wave induced) is determined from the following relationship.

π D du Fm = ρ Cm dt 4 2

where

F

m

= unit inertia force acting normal to the pipe axis [N/m]

C

= added mass coefficient

du dt

= liquid particle acceleration normal to the pipe axis [m/s2]

m

The following table taken gives recommended coefficients. See also DNV 1996 Pipeline Rules.

Steady current

Combined current

Wave induced current

(Uwi ≤ 0.2U)

(Uwi ≤ 0.7U)

2 (Uwi > 0.7U)

Cd (Concrete coated) 1.0

1.2

1.7

Cd (clean)

0.7

0.9

1.4

CL

0.7

0.9

1.0

Cm

-

3.3

3.3

Note: 1)

Uwi = wave-induced velocity; U = total velocity

2)

These values for Cd and CL are in principle only valid for diameters below DN 300 (12 in.) or for velocities above 2 m/s. For larger diameters or lower velocities Cd and CL vary with the Keulegan-Carpenter number (Kc = Um T/D) and may be considerably higher. In that case the advice of specialists is required, although the above values can give a sensitivity check for calculation purposes.

2.13.6 Wind Forces These forces are assumed to act normal to the pipe axis - in the plane defined by the pipe axis and the wind direction. The "static" wind force per unit length of a pipe may be determined by the following formula:

Fw = 0. 613 Cw v w Dt 2

Approved:2009

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JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

where

=

Fw

wind force per unit length, acting normal to pipe axis [N/m]

Cw =

drag coefficient according to table below

vw

=

component of wind velocity normal to pipe axis [m/s]

Dt

=

total outside diameter of pipe, including coating [m]

The drag coefficient should, strictly, depend on wind velocity, pipe diameter and surface roughness. However, the following coefficients may be used for individual pipes. External Pipe Surface

Pipe Diameter

Smooth

Rough

D ≥ 0.2m

0.7

0.8

D < 0.2m

1.2

1.3

2.13.7 Point and distributed loads Point loads can be introduced on pipelines for example by laybarge rollers and pipeline supports. A detailed finite element analysis of the stresses induced is usually not warranted. However, for checking purposes, one could use the analytical solution of a unit pipe diameter long thin tube supported at the base and loaded by its own weight. For buried pipelines the stresses induced due to soil cover and wheel loadings may be calculated as follows:

σb = Where:

wDt 6

3

1. 42 x 10 t + 2 .18 P D

3

σ

= induced bending stress [MPa]

w

= uniformly distributed load acting on pipe [N/m]

D

= outside pipe diameter [m]

t

= pipe wall thickness [m]

P

= internal pressure [MPa]

b

The pipe load may be estimated from:

w = 1800 H D + 0. 72

LD H

Where:

Approved:2009

2

H

= burial depth to top of pipe [m]

L

= wheel load [N] Page 42 of 72

JV VIETSOVPETRO

RULES FOR OPERATION, INSPECTION AND MAINTENANCE OF OFFSHORE PROCESS PIPING AND UNDERWATER PIPELINES

Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

The induced bending stress in direct combination with the hoop stress should remain below the allowable stress limit. 2.13.8 Thermal loads Thermal expansion loadings generally cause few problems both onshore and offshore Brunei. This is due to low variations in ambient temperatures and small differences in operating and surroundings temperatures. The thermal expansion of a long pipeline, subject to axial soil friction and constant temperature loading is:

δ =

where:

La = where:

μW 2 La 2EA

α E A ΔT μW δ

= expansion at the end of the pipeline [m]

μ

= pipe-to-soil axial friction coefficient

W

= pipe submerged weight [kN/m]

EA = pipe axial stiffness [kN] La

= anchor length of pipeline developing friction [m]

α

=

ΔT

= operating temperature minus installation temperature [°C]

-6

linear expansion coefficient [11.7 x 10 /°C]

2.13.9 Unsupported spans Pipelines are regularly subjected to spanning caused by scouring and coral areas respectively. Scouring takes place around many jackets leaving the riser, riser bend, and a section of pipeline free of the seabed. A pipeline crossing another pipeline by means of (sandbag) support at regular intervals, may also be subject to a multiple number of unsupported spans. The method of assessing maximum allowable span length considers three primary conditions: a.

Loaded with functional loads only

b.

Loaded with functional plus environmental loads

c.

Loaded cyclically due to vortex shedding (which induces a cyclic bending stress)

Note that when a pipeline, which has already been installed, subsequently needs to be supported, it should be lifted up to a neutral (level) position before the supports are placed in order to ensure that there is no sagging left in the line. If this procedure is not followed Approved:2009

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Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

the remedial effect of providing supports is minimised as the line will remain in a stressed condition. The functional loads on a pipeline span are pressure and bending (due to pipeline weight only). The pressure induces a hoop stress of β times the yield stress (σh = β σy) in the pipe and an axial stress σa1 (due either to end-cap effect or Poisson effect).

σh =

or

PD = β σ y tensile (see section 2.13.2) 2t

σ a1 = 0.5 σ h

tensile (for axially unrestrained pipeline - end-cap effect)

σ a1 = − 0. 3 σ h

compressive (for axially restrained pipeline - Poisson effect)

The bending load induces an axial stress σa2 component (the bending stress) of α times the yield stress such that:

σa2 = + α σy or - α σy The total axial stress, σa, is summed algebraically to give:

σa = σa1 + σa2 The equivalent stress is:

σ eq =σ y (α 2 +0.75β 2 ) Rearranging gives:

⎛ σ eq 2 ⎞ α = ⎜ 2 −0.75β 2 ⎟ ⎜σ ⎟ ⎝ y ⎠ The factor β is determined by the design pressure of the line. The ratio of equivalent to yield stress is governed by the acceptance criteria. For the functional loads the limit is 72% and for functional plus environmental loads, the limit is 96% as shown for Zone 1 in Table 2 of Section 2.13.2. Substitution of these ratios provides one value for the ratio α and multiplied by the yield stress the maximum allowable bending stress. The bending stress induced by submerged weight of the pipeline, ws (uniform load) on the pipeline span can be determined by modelling the pipeline as a beam, with an average support condition between a simply supported and fixed end. 2

M=

Approved:2009

ws L 10

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Chapter 2: Pipeline Design

Revision: 00

σb = M D 2I

I=

where

π 64

(D

4

and

−(D − 2t )

4

)

M

=

induced bending moment [N m]

ws

=

uniform distributed load rate [N/m]

L

=

span length [m]

D

=

pipe outside diameter [m]

I

=

area moment of inertia [m ]

t

=

pipe wall thickness [m]

=

bending stress [Pa]

σ

b

4

The shear stress induced by the submerged weight [ws] (uniformly distributed load) on the pipeline span may be similarly determined by modelling the pipeline as a beam, with an average support condition between a simply supported and fixed end.

σs = where Fs =

Fs A

ws L = shear force 2

A = Cross section area of the pipe

(D − (D−2t ) ) 4

π

=

2

2

The equivalent stress is calculated using von Mises criterion (see section 2.13.2). Note from 2.13.2 that the equivalent stress is maximised when σb is negative, i.e. compressive. Also, the equivalent stress shall not exceed α, where α is the limit value shown for Zone 1 in Table 2 of Section 2.13.2. Therefore, the maximum allowable span length, [Lmax] occurs when σb is maximised such that = σeq = α x SMYS. Substituting σb into the combined stress formula gives:

⎛σ h ⎛σ 2⎞ 2⎞ 2 2 −α Lmax ⎟ −σ h ⎜ h −α Lmax ⎟+ β Lmax =(%SMYS ) ⎝ 2 ⎠ ⎝ 2 ⎠ 2

σ h 2 +⎜

solving for Lmax :-

Approved:2009

α 2 Lmax 4 + β Lmax 2 +

3σ h 2 =(%SMYS ) 4 2

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where :

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Doc. No.: VSP-SR-16

Chapter 2: Pipeline Design

Revision: 00

α = ws D 20I 2 β = 3 w s2

2A

To determine the maximum allowable span length, under the functional plus environmental conditions, the submerged weight should be combined with wave and current induced drag lift and inertia forces, see section 2.13.5. Therefore :-

{

q = (W − FL ) + (FD + FM ) 2

2

}

where: F = drag force due to 100 year return wave and current induced velocity (see D section 2.13.5) FL = Lift force due to 100 year return wave and current conditions FM = inertia force due to 100 year return wave and current conditions The coefficients for drag, lift and inertia should be obtained from DNV Rules. Note, the coefficient will be different than for an on-bottom pipeline due to the gap between bottom-ofpipe and the seabed. In accordance with Table 2 of Section 2.13.2, the equivalent stress shall not exceed 90% of SMYS. Similar to the approach adopted for functional loads, Lmax can be solved:

α 2 Lmax 4 + β Lmax + 2

3σ h 2 ≤(0.9SMYS ) 4 2

α = ws D 20I where : β =3ws

2

2A2

and

The third load condition to be analysed is fatigue, due to vortex induced vibrations. These vibrations only occur within certain ranges of cross-flow velocities. In order to determine these ranges the natural frequency of the span or riser first needs to be established. The first mode of vibration of a span with the "average" support condition is:

Fn =

Where: F = n

E =

Approved:2009

2.56 ⎛ E I ⎞ ⎜ ⎟ L2 ⎝ M ⎠ -1

natural frequency [s ] 5

Young's Modulus of elasticity = 2.05 x 10 [MPa]

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M = virtual mass per unit length i.e., mass per unit length of pipeline including the coatings and contents plus the mass per unit length of displaced water [kg/m] For a steady state flow, the frequency of the vortex shedding Fv can be evaluated using the formula below:

Fv = Where:

Su D -1

Fv

=

S

=

Strouhal number

u

=

steady current velocity, excluding wave induced current, [m/s]

vortex shedding frequency in water [s ]

The Strouhal Number depends on the drag coefficient Cd which in turn depends or the Reynolds Number Re of the current flow. The span is considered safe if the span natural frequency is 1.3 times the vortex induced frequency. Thus the span length should be less than:

⎛ EI D2 L=3.15⎜⎜ 2 ⎝ MU Where:

=

U

1/ 4

⎞ ⎟⎟ ⎠

Wave or current ratio

2.14 On-Bottom Stability 2.14.1 General Submarine pipelines should have a submerged weight of sufficient magnitude to provide adequate stability on bottom of the seabed. The required minimum weight can be achieved by providing a concrete coating. The pipeline should have such a weight that it will not move from its as installed position, apart from movements corresponding to permissible deformation, thermal expansion (if applicable) and a limited amount of settlement after installation. 2.14.2 Analysis The on-bottom stability limit is reached when the water particle induced forces on the pipeline are equal to the lateral (frictional) resistance of the pipe:

Fd + Fi = μ ( W − FL ) where Approved:2009

Fd

=

drag force [N/m] Page 47 of 72

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Fi

=

inertia force [N/m]

μ

=

pipe to soil friction factor

W

=

pipeline submerged weight [N/m]

FL

=

lift force [N/m]

The wave and current induced drag, inertia and lift forces are detailed in section 2.13.5. These forces are time dependent, due to the periodicity of the waves. As the maxima for the drag, inertia and lift forces are out-of-phase, the phase angles have to be taken into account, when evaluating the above limit. For gas lines, the on-bottom stability should be ensured under 100 year return wave and current conditions. Oil pipelines should also meet this criterion, but in addition should be stable during installation. The submerged weight of an oil line during installation is lower than during operation, since the pipe is filled with air rather than oil during laying. In the latter case, the 1 year return wave and current conditions are applied, as the installation duration is short. The soil friction factor varies with the pipeline surface material and seabed surface condition. The following values are recommended:

μ = 1

for soft silty areas

μ = 0.7 for rocky, sandy areas The hydrodynamic coefficients and safety factors are based on the simplified method included in DNV's recommended practice. This method is nowadays applied in its entirety. 2.14.3 Concrete Weight Coating The concrete weight coating requirements of each pipeline should be evaluated on an individual basis. In general pipe sizes DN100, 150 and 200 have been found to require no concrete coating, depending on the water depth and environmental conditions. In some shallow water depths the DN100 and DN150 gas lines may need 25 mm or more concrete if lying individually, for stability. If they are part of a bundle, attached to a flowline or liquid filled line, it is usually not required. Also in soil conditions where the line will sink wholly or partly the drag force and lift force will be reduced considerably. Initially however the line is assumed to be laid on top of a well defined seabed. 3

3

The standard density for concrete coatings is 2243 kg/m (140 lb/ft ) but a more dense mix 3 3 of 3044 kg/m (190 lb/ft ) is also used where coating thickness has to be minimised. Water absorption of upto 3% of the concrete weight is allowed but may not be applied when designing the weight coating. In deciding between a combination of concrete thickness and density, to give the required submerged weight, the following points should be considered:

Approved:2009

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•

The minimum practical thickness of concrete coating is 25 mm and for marginal cases of instability without concrete coating, additional pipe wall thickness may be the most economical solution.

•

When sacrificial anodes are needed, it is desirable to have a concrete coating to give a continuous external diameter.

•

For laybarge installation, it is desirable to provide mechanical protection of the bitumen corrosion coat by the application of a concrete coating.

Concrete coating and the field joint infill mode should follow the relevant VIETSOVPETRO JV specification. The submerged weight calculation routines should be included in the on-bottom stability calculation. In case the steel wall thickness includes a corrosion allowance, the submerged weight of the pipeline reduces with time. At the design stage, it may be assumed that, at the end of the service life, 50 % of the corrosion allowance will still contribute to the submerged weight, since the corrosion itself is usually not perfectly uniform. 2.14.4 Shore Approach Selection of a shore approach and landfall location requires careful consideration of bathymetry, seabed characteristics, wave and current data, location of other facilities, onshore routing constraints, etc. Particular design aspects to be addressed are:

•

Required length of trenched and buried section.

•

Required burial depth, method(s) of trenching/burial, and selection of backfill material.

•

Laybarge access, and length of pipe pull to shore.

•

Pull loads, pull-in winch capacity and location.

•

Onshore construction and tie-in procedures (if applicable).

•

Alternative shore approach construction methods, such as remote pipe string fabrication and tow-in.

In all cases the safety of the proposed design shall be adequately demonstrated. For all shore approaches, an environmental impact study shall be conducted, assessing, among others, the impact of temporary end permanent trenches on the stability of the shoreline. In general, good engineering judgement shall prevail in each situation end the required length of trenches should be optimised to minimise cost while ensuring pipeline integrity The stability afforded by the pipeline submerged weight should also be taken into consideration. Normally, a pipeline at an approach to the shore is buried to provide on-bottom stability. The pipeline should have sufficient weight to prevent it from surfacing due to soil liquefaction. The approach to shore should be perpendicular to the shoreline in order to minimise coastal erosion especially where trenching is required. Based on experience with shore approach design, it is recommended that the as-laid Specific Gravity (SG) of the pipeline exceeds 1.8. The SG is defined as the weight in air divided by the weight of the displaced water. Approved:2009

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2.15 Riser design 2.15.1 Components The riser is the vertical or near vertical section of a submarine pipeline which connects the pipeline on the seabed with the facilities on an offshore platform or jacket. The riser design factor is lower than the pipeline design factor (see section 2.10.3), resulting in a thicker pipe or a higher grade material. The latter option has the advantage of maintaining a constant internal bore for the complete pipeline system. Risers and expansion spools shall be designed according to the requirements for Zone 2 areas as shown in Table 2 of 2.13.2. Risers typically are attached on the outside of the jacket and held in place by riser clamps (guides). The riser is normally allowed to slide in the longitudinal direction within each clamp (guide). The vertical loads are therefore normally taken up by the deck support. Scouring underneath the riser bend and over a length of approximately 15 m underneath the pipeline should be taken into account, resulting in the vertical support carrying approximately 95% of the riser load, including the ESD and 7.5 m of pipeline length at the seabed. The riser clamps have in the past typically contained 6 mm polychloroprene ('neoprene') rubber sheeting inside the clamp shell to isolate the riser from the cathodic protection system of the jacket. Severe external corrosion is experienced underneath riser clamps in the splashzone, probably because the clamps are fit tight to the riser, or disbondment occurs giving rise to crevice type corrosion. A more suitable material for clamp shells is composite thermoplastic sheeting (Ultra-high Molecular Weight Polyethylene or UHMW-PE). This lining material consists of a double layer sheet: a thermoplastic outer layer which is in contact with the riser and a natural rubber inner layer which is glued to the clamp shell to aid installation. The thermoplastic surface has a low friction coefficient which allows free sliding of the riser in contact with it and is hence unlikely to cause frictional tearing of the paint coating. The sheet is extended from the clamp shell over the flat flange faces as well and pre-drilled holes in the sheet allow the clamp bolts to be passed through and tightened up over the sheet thus locating it firmly inside the clamps. To prevent boat impact on risers, a boat fender is normally provided. Alternatively, one could consider locating the riser on the inside of the platform. The latter approach is, however, not very practical from an installation and repair point of view. Where the pipeline cathodic protection system is different from the system used for platform cathodic protection, isolation of the two systems is required, in order to prevent any adverse effects on the pipeline from stray current interference. Whereas in the past insulation flanges have been used for this purpose, experience has shown that these deteriorate in time and become ineffective. Hence monobloc insulation joints shall be used instead where there is a requirement to isolate the pipeline from the platform CP system. Many of the new risers are fitted with an ESD valve located at the working height above the spider deck (about 3 m above mean sea level), where a perimeter walkway is usually available. As a consequence, the insulation joint will be very close to the ESD valve flange.

Approved:2009

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Typically a jacket has a 1:10 batter, usually resulting in the need for a 5° bend. A mitre not exceeding 3° should only be used during the construction hook-up of the riser to accommodate misalignment. A knee brace is only necessary for the installation of risers. After installation, the knee brace shall be removed by divers, to minimise operational stress levels. All riser bends shall have a minimum radius of 5 pipe diameters (R=5D) to facilitate pigging operations. However where space is limited on existing facilities a 3D bend radius may be considered, subject to approval by VIETSOVPETRO JV. 2.15.2 Riser coating The small diameter risers are usually Polyethylene (PE) coated and the large diameters with coal-tar enamel and concrete. Concrete weight coating is only applied to ensure that the riser is negatively buoyant under operational conditions. The splash zone is the region which is most severely exposed to wave action, including the tidal zone (approximately ± 6 m from mean sea level). In this zone a 12m riser joint is installed with bonded, reinforced polychloroprene ('Neoprene', 'Splashtron' or equivalent) rubber. Significant disbondment is experienced with this coating. Alternatives which may be used are, for example, PE coating and monel cladding. The section above the splashzone and the riser bends are normally asphalt enamel painted. 2.15.3 Passive Fire Protection The benefits of providing passive fire protection around the above water section of the riser is to prevent escalation due to flame impingement from adjacent existing risers and to enable personnel to evacuate the facility safely during such contingency. Historical data which is applicable to the company offshore installations indicates that the highest risk area for riser corrosion failure and collision damage is in the splash zone. Passive fire protection (PFP) is required for all gas risers on manned facilities offshore unless it can be demonstrated by an adequate and approved QRA that for a given installation the risk is considered to be of little or no consequence to the safety of personnel. It is also normally only required where the riser to be installed will be located adjacent to existing risers. Such considerations should preferably be carried out during the conceptual design stage of a project. Passive fire protection, where required, shall be applied from at least -2.0m below MSL up to the lower flange connection of the first ESD valve. Riser support members over this length shall also be protected. The valve and actuator do not require protection. The PFP system shall not accelerate corrosion of the riser. There shall be sufficient overlap between the PFP and the splash-zone coating to prevent ingress of moisture. The system shall stand up to exposure from a jet fire for a period of at least 30 minutes (i.e. JF30) or longer as may pertain to the evacuation requirements of the facility concerned. The surface temperature of the riser shall remain at < 200°C for the required duration of exposure and the temperature of riser support members (clamps, etc) shall remain at < 400°C for the required duration of exposure.

Approved:2009

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All passive fire protection systems proposed by Vendors, Consultants or Contractors shall be supported by certification and / or approval by an internationally recognised Classification Society such as Lloyd's Register, Det norske Veritas or Bureau Veritas. 2.15.4 Pipeline approach and riser bend angle The riser bottom bend angle depends on the jacket batter and the pipeline jacket approach angle, as follows:

β = acos{cos(χ)sin(α)} where

Usually

β

=

riser bend angle

χ

=

angle between jacket face and pipeline in the horizontal plane (0° is perpendicular to jacket face)

α

=

angle between jacket face and the vertical plane (jacket batter).

α

=

5.7° for structures, so the following values result:

χ

β

0°

84.3°

30°

85.1°

45°

86.0°

60°

87.2°

90°

90.0°

The bends are procured to the bending specification, which calls for a bend angle tolerance of ±1 degree. 2.15.5 Riser Clamp Positions The riser clamps are normally attached to the jacket horizontal bracings. The above water clamp should preferably be well above mean sea level to prevent external corrosion of the riser and clamp. The height of the lowest riser clamp above the seabed should be sufficient to limit the stresses induced in the riser during a 100 year storm. A simplified approach to analyse these stress is to model the section of riser between the seabed and the first riser clamp as a cantilever beam. The bending moment M at the base of the riser (cantilever) due to a horizontal deflection of the jacket at the clamp, during a 100 year storm, is given by:

M = Approved:2009

3EIδ 2 L Page 52 of 72

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and associated bending stress is given by :

σ b = M2 ID where

M

=

bending moment [N m]

E

=

Young's Modulus of elasticity [N/m2]

I

=

moment of inertia [m ]

δ

=

horizontal deflection jacket at lowest clamp [m]

L

=

distance to lowest clamp [m]

D

=

outer steel diameter [m]

σ

=

bending stress [Pa]

b

4

The equivalent stress of the combined bending and hoop stress is not allowed to exceed 67% of the yield stress, i.e. the stress limit for risers when taking into account both the functional and the environmental loads (see section 2.13.2). From the formula, one can conclude that the first subsea clamp should be located as high as possible, since the bending moment reduces quadratically with the distance L. Additional bracing a few metres above sea bed should thus not be used. However, to avoid vortex induced vibrations, the unsupported riser length should not exceed the following limit (see section 2.13.9):

⎡ E Ig D 2 ⎤ L=3.15⎢ 2 ⎥ ⎣⎢ M U ⎦⎥

1

4

The above approach is not entirely conservative, as not all the environmental loads have been taken into account; the wave and current induced drag forces have been neglected. However, these forces are usually negligible. Nevertheless, for the design of large risers it is recommended to perform a full finite element analysis, for example with the computer program RISR or equivalent. 2.16 Corrosion 2.16.1 Design Life A pipeline is designed for a limited functional lifetime, typically 30 years for offshore lines. The major factors which govern the potential lifetime duration of a carbon steel pipeline are composition of transported medium and the environmental conditions. Alternative materials to carbon steel are briefly discussed in section 2.7. When pipelines are taken out of service they are either mothballed (preserved with inhibited water to arrest internal corrosion) or abandoned. As such they should not be generally considered fit for purpose at a future date. Mothballed lines may be considered for re-use subject to proof of mechanical integrity (by intelligent pigging or hydrotest to a sufficiently Approved:2009

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Revision: 00

high pressure so as to prove integrity with regard to existing defects). Abandoned pipelines are considered to have been left in a state such that they are not in any way preserved from ongoing corrosion or deterioration to their physical condition. Abandoned pipelines should therefore not be re-used for transport of any product as they are considered as having been scrapped at the point of abandonment. 2.16.2 Composition of Transported Medium Hydrocarbons being transmitted through a pipeline consist of great varieties of components such as methane, ethane, propane, iso-butane and so on. In addition, they also contain corrosive elements such as water, dissolved gases (oxygen, carbon dioxide and hydrogen sulphide), and formation debris such as sand. All internal corrosion problems which occur in oil field pipeline operations are due to the presence of water. Of the three dissolved gases mentioned, oxygen is by far the worst of the group. If present, it can cause severe corrosion at very low concentrations (less than 1 ppm). It is a strong and rapid oxidising agent in cathodic reactions. When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH of the water, and increases its corrosivity. It is not as corrosive as oxygen, but usually results in pitting. Corrosion primarily caused by dissolved carbon dioxide is commonly called "sweet" corrosion. Hydrogen sulphide is very soluble in water, and when dissolved, behaves as a weak acid and usually causes pitting. Attack due to the presence of dissolved hydrogen sulphide is referred to as "sour" corrosion and normally takes the form of stress corrosion cracking or hydrogen induced cracking. Sulphate Reducing Bacteria (SRBs) may occur in, or have been introduced to, the formation water. 2.16.3 Environmental Conditions External corrosion to offshore pipelines is prevented by coatings and cathodic protection either by sacrificial anodes or by impressed current. The sections above water can only be protected by external coatings. The splash zone area is protected by the 'Splashtron' coating but any damage to this can result in rapid corrosion. Onshore pipelines below-ground are generally only protected by external coatings although at present sacrificial (magnesium) anodes or impressed current systems are being installed on all new lines. The resistivity of the soil controls the corrosion of below-ground pipelines. In general the higher the resistance of the soil the less likely is corrosion and the less effect any cathodic protection measures may be. Typically, lower resistance soils are found in the areas of rivers, ditches, and close to the shore. Pipelines above-ground and on racks can only be protected by external coatings. These coatings have to be resistant to sunlight and usually consist of polyurethane paints. Surface laid pipelines are heavily prone to corrosive attack. The upper areas of coating are degraded in the sun and the lower areas are kept continually moist. Many surface laid pipelines are being removed.

Approved:2009

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2.16.4 Corrosion Inhibitors Where the internal corrosion of carbon steel pipelines is expected to be high or bacterial action is expected, chemical injection may be applied. The effectiveness of inhibitors generally depends upon the flow regime existing in pipeline and the level of wall-wetting. In general if annular dispersed, slug, or bubbly type flow exists in a pipeline then continuous inhibitor may be applied. If stratified flow conditions exist then batch inhibitor may be considered. The computer program PIPESIM may be used for flow regime prediction. 2.16.5 External corrosion coatings The corrosion coating system to be used on marine pipelines to provide protection against external corrosion will depend upon the pipeline installation method, the method selected for obtaining adequate specific gravity, time required for applying of coating, and cost. In general, Polyethylene (PE) is used for small diameter pipelines not requiring any concrete weight coatings. For the large diameter pipelines, asphalt enamel and wrap is applied, in combination with a concrete coating. For the riser protection see section 2.15.3. For onshore, below-ground pipelines are normally PE coated. For the field joints, the application of heat shrink sleeves are preferred, but tapes might be acceptable. All aboveground pipelines are painted in accordance with the painting specification. Air/ground interfaces are taped following the tape specification. For high-temperature service the use of polypropylene or EPDM coatings could be considered. Service temperature limits for external corrosion coatings are tabulated below:

Coating type Hot applied asphalt enamel Fusion bonded epoxy or FBE Polyethylene Polypropylene or EPDM

Max. temperature [°C] 60 70 65 > 80

2.16.6 Cathodic Protection A Cathodic Protection (CP) system provides a secondary protection against external pipeline corrosion. The corrosion coating constitutes the primary protection. The CP system can be classified as an impressed current system or a sacrificial anode system. The impressed current system consists of an external current source, such as a battery, a rectifier or a solar panel. The sacrificial anode system is based on the galvanic cell principle created by connecting a sacrificial metal anode, with a potential lower than steel, to the pipeline at regular intervals. The pipelines have been normally protected by an impressed current system. A sacrificial anode system was only applied if: Approved:2009

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•

it was not possible to install an impressed current system, because of lack of power supply,

•

an impressed current system induces stray current effects,

•

the pipeline was in excess of 35 km in length.

The use of sacrificial anodes on all subsea pipelines are based upon the following reasons: 1. Elimination of monitoring and maintenance requirement (impressed current system) 2. Self-regulating nature of sacrificial anode system 3. No operator intervention for correct functioning 4. No risk from incorrect connection The design, procurement and installation of a cathodic protection system is covered by specifications for offshore lines and for all onshore/offshore pipelines. Most of pipelines are electrically isolated from the upstream and downstream facilities by insulating flanges. For the design of new offshore subsea pipelines the use of insulation flanges is no longer sanctioned, for reasons already stated in Section 2.15.1. Monobloc insulation joints shall therefore be used instead, which provide more reliable long term electrical isolation between the subsea pipeline and the platform structure. 2.16.7 Strength Assessment When internal or external corrosion has been found, a pipeline may still be operated although in some cases this may require reduction of the maximum allowable operating pressure, MAOP, or derating. In determining the derating required, step one is to check the corrosion allowance designed into the pipeline. The minimum steel wall thickness tm is equal to the nominal thickness minus the corrosion allowance. If the remaining wall thickness exceeds the minimum thickness, no derating is required. If the remaining thickness is less than the minimum, then a derating equation is applied. The most common de-rating equation is contained in Appendix L of the B31.8 code. Billiton Research Arnhem (BRA) has slightly modified the formulae. The BRA method is now used in preference to the B31.8 method. The MOP of the derated pipeline shall be checked and confirmed to be below the derated MAOP. 2.17 Installation Analysis A riser installation stress analysis shall be performed to ensure that the riser and adjacent sections of pipeline are not overstressed at any stage. Stress limits are defined in Section 2.13.2. If a large thermal offset is not required, the 'stalk on' method of installation shall be considered as the base case. The analysis shall simulate all lifting and hold-hack lines, supplemental buoyancy, and any other applied loads. Unless alternative data is available, the following barge characteristics shall be assumed for davit lift of the pipeline end Approved:2009

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•

Barge length 122 metres

•

Number of davits 5

If necessary, alternative installation methods such as J-tube pull, bending shoe, subsea flanged tie-in, hyperbaric welding, etc. may be considered. Lift analyses of expansion spools and risers shall be performed where relevant. A dynamic load factor of 2.0 shall be applied to all static lift forces in accordance with API RP 2A. 2.18 Pipeline pigging 2.18.1 Internal Diameter Inspection Pigs Upon installation of a new pipeline it is necessary to ensure that no deformations or obstructions are left in the pipeline. Dents or buckles create localised stress areas, increase turbulence, and form potential pig blockages. (The term ‘pig’ is believed to have been derived from ‘pipeline inspection gauge’). Gauging pigs are used to ascertain the dimensional condition of the pipe internal diameter. Such a pig is fitted with a thin aluminium plate with a diameter smaller than the pipe internal diameter. If the gauging plate passes the line without any damage, the internal dimensional condition is acceptable. It is important that the plate diameter selection is based on the narrowest bore section (i.e. usually the thickest pipe wall) and will pass all the bends, flanges and fittings. Normally the diameter is based on the following formula:

D p =0.97{Do − 2(1.15t )} − 5 where

Dp

=

diameter of the gauging plate [mm]

Do

=

nominal outer diameter steel pipe [mm]

t

=

nominal steel wall thickness [mm]

This diameter is based on a pipe diameter out-of-roundness of 3%, a wall thickness tolerance of 15 %, and a clearance of 2.5 mm (includes 1.6mm clearance for the inner weld bead). If the gauging plate is damaged, it is difficult to trace the location of the dent or debris along the pipeline. Under those circumstances, it is recommended to run a geometry inspection pig. This pig measures the internal diameter over the entire length of the line, but is more expensive. 2.18.2 Cleaning and Batching Pigs Cleaning pigs are used to maintain the pipeline throughput efficiency and to minimise internal corrosion. Batching pigs are used to separate one fluid from the other, for example to de-water a pipeline using gas. Approved:2009

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In a natural gas transmission line, compressor oil overflow can combine with dust, distillate, and minute droplets of water in the gas stream and coat the inside of the pipe. Wax and sand deposition in crude lines and liquid hold-up in 2-phase flowlines both increase resistance to flow which in turn decreases pipeline efficiency and increases cost of transmission. Internal corrosion is intensified and corrosion control is made more difficult by the accumulation of silt, sand, mud, completion fluids, stagnant water and bacterial deposits. The majority of the chemicals used for corrosion inhibition are metal-surface active and are adversely affected by the presence of these accumulations. For example in the case of bacterial corrosion, deposits give shelter to bacteria permitting their population expansion. Periodic cleaning of a pipeline will help considerably to control many of these corrosion factors. Routine operational pigging for cleaning purposes should form part of the overall plan for the maintenance of pipelines, and should be defined in the context of the Pipeline Integrity Management System (PIMS). It should be remembered that the cleaning operation can be carried out without seriously affecting the operation of the pipeline or its throughput. The frequency of cleaning pipelines can best be decided after an initial programme has been carried out. During this period, careful records should be kept as to the amount and nature of contaminating material removed. Frequency once established, can be changed when operating conditions change (e.g. the introduction water injection). The high capital cost of installing pipelines, together with their strategic value once they are operating, make it imperative that corrosion is controlled as much as possible. Pipeline pigging, as outlined above, has a significant role to play in extending pipeline life in exchange for a small increase in operating costs. PIMS recommends that pigging requirement and frequency are determined by the criticality rating of each line which is based upon the risk and consequence of a line failure. A wide range of cleaning and batching pigs are available such as a cup type, foam type and sphere type. Inflatable polyurethane spheres are commonly used. They can be sized to any pipe bore within the same nominal pipe size. They are very useful in cases where an undersized sphere is required. Correct inflation of these spheres is critical to the sphere's performance and the inflating medium should be water. Before inflating the sphere, the sphere pump and connections should have all air bled out and the sphere should not contain any air after inflation. For cleaning operations spheres should be sized exactly on the pipe internal diameter. For batching operations the sphere should be inflated some 3% greater than the internal diameter of the pipe in which it will run and this should be checked with callipers. Spheres may get stuck or hang at large branch tees, i.e., where branch diameter is similar to run diameter. In these instances “sphere” tees are preferred. In general, mandrel pigs such as cup pigs or bi-directional pigs are more efficient than sphere pigs and where practicable these should be used in preference to the above. It is essential to check the by-pass ports on pigs prior to insertion. For wax removal service it may be desirable to secure a degree of by-pass flow to prevent wax scrapings combining to seize the pig's transit. On new pipelines it is recommended that a brush pig is run, with the aim of 'polishing' the internal bore in order to obtain optimal pipeline efficiency and reduce scale accumulations. Approved:2009

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Note, based on previous experience, the use of spring mounted brushes is not effective in removing scale (do not provide enough pressure). Fixed brush pigs have been proven more effective. 2.18.3 Corrosion Inspection Pigs A number of corrosion inspection tools, e.g. intelligent pigs, have been developed to inspect the wall condition of in-service lines. A log is made of the extent of both wall thickness loss and defect size. As an aid in the evaluation of corrosion inspection tools and to provide a check of the tool calibration a 'pull through' rig where the tool is pulled through both before and after an inspection run. This ensures that the tool calibration has not been altered during operation and that it has produced consistent results. The test rig is also used to check on interpretation of defects. 2.18.4 Pinger Pigs Pinger pigs are used to locate a pipeline obstruction. By tracking the signal emitted from a pinger mounted on the pig, the pig can be located when it becomes blocked at the obstruction. The acoustic pingers usually used have a signal life of either 10 or 30 days. They only emit an acoustic signal when they are wet and can therefore only be used for liquid (hydrotest water) filled pipeline. The pinger can be installed inside a perforated protection cage, usually mounted at the rear end of the pig in line with the pig body. For bigger pipelines the pinger cage will be incorporated in the pig body. 2.18.5 Pipeline Design for Pigging The simple rule when designing a pipeline which requires pigging: is keep the internal diameter constant. In most pipelines this is simply not possible; changes in wall thickness may be required to comply with codes and manufacturing tolerances. The rule should therefore be modified to read; keep internal diameter variations to a minimum and constantly check with pig vendors that their tools can tolerate the variations expected. Particularly in the case of intelligent pigs it is essential to confirm with the vendor that the pig can traverse the minimum bend radii in the pipeline system. On short-radius bends additional wall thickness is allowed to compensate for thinning during the bend-forming process. Such wall thicknesses may impinge on essential clearances. Some specific recommendations are listed below:

•

Check with manufacturer on tolerance of pig for internal diameter, dents, and bends for the pipe size in question.

•

Specify all fitting (flanges, tees) to have the nominal pipe inside diameter.

•

Specify all tees to have guide bars following the standard drawing.

•

Specify all valves to be full bore, in accordance with API 6D and with the nominal pipe ID. If gate valves are selected the through conduit type should be specified. Wedge type gate valves have cavities in which by-pass across the pig can occur causing the pig to stop. This is particularly true when spheres are used.

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•

Fittings should never be located close together. A space of at least 3 pipe diameters of straight pipe should be left between fittings.

•

Bends shall normally be of 5D radius (5 times nominal diameter). This requirement may be relaxed where topside space is limited, but only on a case-by-case basis. (See section 2.15.1)

2.18.6 Pig Launcher and Receiver Four pig launcher/receiver standard mechanical drawings are available, these are:i)

Scraper Launcher/Receiver facilities (with double block and bleed)

ii)

Scraper Launcher/Receiver Facilities (without double block and bleed)

iii) Intelligent Pig Launcher/Receiver Facilities (without double block and bleed) iv) Intelligent Pig Launcher/Receiver Facilities (with double block and bleed) In general, double block and bleed isolation is only required in high pressure, toxic or critical service. For specific requirements refer to the EP safety manual. For operating launchers/receivers refer to the relevant Operating Bulletins. Additional considerations are:

• Drain pit

-

A drain complete with grate cover and drain piping connected to the oil sump should be provided at the trap door.

• Closure

-

The trap door should be a quick opening type with a self-sealing gasket, pressure locking device and hinge support designed for one person operation.

• Hoisting

-

A suitable hoist and trolley arrangement should be provided for handling DN400 and larger scrapers. Hoisting equipment or suitable counter balance weights should be installed on inclined or vertical trap closures where required.

• Service

-

Consideration should be given to provide a service platform on traps above 1.5 m elevation for ease of operation.

• Thermal

-

A thermal relief valve is normally not provided on relief pig traps, firstly because liquids should always be drained from the trap and secondly because ambient temperature fluctuations are relatively small.

In line with operational experience, vertical launchers should not be used for the following reasons:

•

where intelligent pigs are used, these may 'flop' under considerable weight and damage cups

•

vertical door opening mechanisms have proved problematic

•

traps cannot be fully drained and residue on valve balls can promote corrosion

•

debris may become lodged in seats causing valve failure

•

pig handling is generally not geared for vertical handling operations

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On many onshore flowlines, ITAG launcher and receiver valve systems have been installed, for cleaning and/or well fluid separation purposes only. The system basically consists of one ball valve with an inlet, outlet and a pig insert/retrieve opening. The unit is relatively easy to operate and is far less expensive than a conventional launcher/receiver unit. They are not provided with isolation valves and bypasses to allow maintenance work without shutting down the system. 2.18.7 Pipelines Requiring Pigging Facilities The requirement for routine (operational) pigging on a given pipeline should be determined from a corrosion assessment for the respective line. The need for intelligent pigging is determined from a risk and consequence ranking assessment (Pipe Line Criticality and Consequence of Failure,) in accordance with VIETSOVPETRO JV Pipeline Integrity Management Manual. The requirements for operational and intelligent pigging are specified in “Maintenance Reference Plan” for each pipeline. The decisions whether to install permanent or temporary pigging facilities are depend on the specified pigging frequency. If pigging frequency of more than once a year is specified, permanent pigging facilities shall be installed. 2.19 Pipeline Material Procurement 2.19.1 General Standard requisition sheets shall be developed as of VIETSOVPETRO format, for onshore and offshore pipeline long lead materials. These sheets are included in Request for Engineering Documents (RED) sheets do not need to be prepared, since these requirements are already covered by the referenced standards and/or buyer descriptions. 2.19.2 Linepipe and bends The linepipe shall be in accordance with API Spec. 5L and for non-sour service or for sour service. The quantity of linepipe required has to be expressed in metres length and has to include a construction allowance. The number of joints does not need to be defined, since they vary in length. Pipeline bends, preferably, have to be manufactured from the linepipe order. Alternatively, the parent material can be supplied by the pipe bender. Hot induction bends should be manufactured from the same parent material as the linepipe, i.e. have the same heat number and kiln batch. All bends shall be supplied and manufactured in accordance with ASME B31.4/31.8. SSU will combine all parent material (bare steel) requirements into one order to be processed by SIEP. It is not required to identify the welding method (seamless, ERW, SAW), since all three methods are acceptable. The MESC number therefore does not need to be indicated. Coating of the linepipe shall be in accordance with the appropriate standard or VIETSOVPETRO JV requirement/standard. Approved:2009

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2.19.3 Flanges Flanges shall be forged in accordance with ASTM A694. To avoid differences in internal diameter of the pipeline versus the flange bore, the flange material grade has to be equivalent to the linepipe material grade. In addition, the nominal internal bore (or pipe wall thickness) should also be indicated on the requisition sheet. 2.19.4 Butt-weld fittings and Barred Tees The butt-weld fittings for pipelines shall be manufactured in accordance with MSS-SP-75. To avoid differences in internal diameter of the pipeline versus fitting bore, the fitting material grade shall be equivalent to the linepipe material grade. The required wall thickness shall be specified on the requisition sheet. Barred tees shall be constructed from a material grade equivalent to the linepipe material grade. Furthermore, bars need to be welded into the tee. 2.19.5 Launcher and Receivers. The long lead items for pig launchers and receivers include a barred tee, full bore valves, barrels, reducers and trap closures. The small end of the barrel has to be constructed from bare linepipe. The larger end of the barrel can be constructed from standard piping or linepipe material. The reducer material should be equivalent to the linepipe material. The wall thickness of the reducer has to be selected such that the allowable stress levels in the large end are not exceeded. 2.20 Pipeline Design Data 2.20.1 Allocation of PID number for new pipelines For all new pipelines a unique 4-digit Pipeline Identification (PID) number shall be obtained from and allocated by the custodian of the Corporate Pipeline Database (CPD). The pipeline engineer shall notify the custodian concerned of the new pipeline in writing, who in turn shall inform the project and design consultants of the same. The PID shall be shown on all drawings, charts and schematics, and in all design documentation as appropriate. 2.20.2 Pipeline Data Sheets Pipeline data sheets summarise the pipeline design, by listing the key parameters. They are usually developed at the end of conceptual design. A typical offshore pipeline data sheets is shown below: General a. Field location b. Service c. Facility From and To d. Nominal Diameter (DN) e. Length (including risers) Approved:2009

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Pipeline Design Data a. Design Life b. Design temperature c. Design pressure d. Corrosion Allowance e. Pipeline intelligently piggable f.

Cathodic Protection Type

Environmental data at Location-1 a. Water depth b. Significant wave height (100 years) c. Significant wave peak period (100 years) d. Maximum wave height (100 years) e. Surface current (100 years) Pipeline Data a. Pipeline outside diameter (steel) b. Pipeline steel wall thickness c. Length (riser base to riser base) d. Line pipe material and grade e. Specified minimum yield strength (SMYS) f.

Anti-Corrosion Coating Type

g. Anti-Corrosion Coating Thickness h. Density of corrosion coating i.

Weight Coating Thickness

j.

Concrete density

k. Pipeline empty weight in air l.

Pipeline submerged weight (empty)

m. Pipeline submerged weight (product) Riser data a. Riser outside diameter (steel) b. Riser Wall Thickness c. Riser Material and Grade d. Specified minimum yield strength (SMYS) e. Riser Min Bend Radius f.

Riser bend angle-1 and 2

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g. Flange rating Installation data a. Pipeline installation method b. Riser setting method c. Gauging plate size d. Hydrostatic test pressure e. Hydrostatic test duration 2.21 Hydrostatic Testing Hydrostatic pressure testing is the accepted method of demonstrating the structural integrity of pipelines after the completion of construction. Prior to commencing the hydrostatic test the pipeline should have been adequately cleaned of construction debris and have successfully passed a gauging plate (preferably aluminium) of 95 percent minimum internal diameter undamaged through the section to be tested. 2.21.1 Testing Requirements The minimum requirements for testing are detailed in the relevant sections of the ANSI B31 .4 and B31.8 Codes and include test mediums other than water. Extreme caution should be exercised if testing with air or gas due to the enormous release of energy in the event of any pipeline failure. A strength test and a leak test (commonly at a lower pressure) may be conducted separately but these can be combined into a single test at the higher strength test pressure provided the necessary test procedures have been established. The minimum recommended duration for a strength test, leak test or combined strength/leak test is 24 hours. For very long pipeline test section lengths, particularly of the larger diameter, leak test durations should be increased after giving due consideration to the volumetric content of the test section, its location and to the detectability of possible small leaks. Variations in pressure during the strength test can be compensated for by the addition or removal of test water to maintain the correct pressure. For the leak test or combined leak/strength test it is not permissible to add water to the test section but water can be removed if pressure build-up is excessive. However any water that is removed should be measured and taken into account in the test evaluation. In general large pressure increases are unlikely to occur unless a significant proportion of the pipeline is exposed to ambient effects. In determining test section lengths, the profile of the pipeline and hence static head pressures are to be taken into account, such that the minimum requirements of the Code are maintained while not exceeding the maximum test pressure. The test pressure itself should not exceed the pipe mill hydrostatic tests (normally 95 percent SMYS based on nominal wall thickness for SIPM specification pipe). Heavier wall thickness pipe installed at special crossings, e.g. roads, can be tested at the same pressure and time as the main pipeline subject to any special provisions in the design or as required by local regulatory authorities. Valves included in a test section should be in the open position.

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In some instances valves are used to segment a completed pipeline for testing purposes. In such cases it is necessary to ensure that the differential pressure across the valve is within its design allowance and that special provisions are made to monitor possible leakage across the valve. Scraper trap facilities included in any test section are to be tested to the same design code as the pipeline. Depending on the quality of the water to be used for hydrostatic testing and/or the length of time it is likely to remain in the pipeline after testing consideration should be given to protecting the pipeline by the addition of inhibitors, biocides and oxygen scavengers. Water analysis should be carried out to determine these requirements. 2.21.2 Test Equipment and Instrumentation FIGURE 7: TYPICAL SCHEMATIC OF TEST SECTION

Legend: PI

= pressure gauge, range 1½ times test pressure

PR

= pressure recorder, range 1½ times test pressure recording time 24 hrs. min.

DWT

= dead weight tester, accuracy 0.01 bar, with current calibration certificate

Tl1

= pipeskin temperature probes, sensitivity 0.1ºC

Tl2

= intermediate pipeskin temperature probes (onshore pipelines only)

Tl3

= ambient temperature measurement, sensitivity 0.5 ºC

M

= volumetric measurement device during pipeline pressurizing i.e. flowmeter or pump stroke counter

2.21.3 Determination of Residual Air Volume in Pipeline The presence of residual air in the pipeline test section will influence the behavior of the test section during the leak test hold period and will tend to disguise the presence of small leaks. It is necessary, therefore, to demonstrate that the quantity of residual air that may be present in a pipeline is below a minimum acceptable value prior to commencing the leak test hold period. Approved:2009

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The method for calculating the residual air volume is demonstrated in Figure 8.0. FIGURE 8: DETERMINATION OF RESIDUAL AIR VOLUME

Method: The air content shall be determined by constructing a pressure/volume plot from atmospheric pressure up to the linear section of the pressure volume plot curve and extrapolating back to the axis. The volume of the air shall then be read directly from the horizontal axis and compared with the total volume of the section. The maximum residual air contained in the system when filled with water shall not exceed 0.5% of the calculated volume of the system. If the air content is found to exceed this volume the section of pipeline shall be refilled. In special circumstances where the availability of water is very limited and it is not practical to refill the pipeline it is possible to proceed with the leak test. However due allowance for the presence of residual air should be included in the evaluation method and where necessary the leak test duration extended accordingly.

2.21.4 Hydrostatic Leak Test Evaluation Prior to commencing the leak test hold period, sufficient time should have been allowed for the pipeline and its contents to stabilise to the prevailing surrounding temperature. Once stabilised the leak test is commenced and, provided the pipeline does not contain a leak or excessive quantities of air, any variations in the test pressure over the hold period should be as a result of minor temperature fluctuations. To determine whether any pressure variations are a result of temperature fluctuation or whether a leak is present, the pressure/volume and temperature/volume relationship for the particular pipeline test section must be considered. For an infinitely long, fully restrained pipeline this relationship is governed by the following equations:

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Where: DV

= incremental volume, m³

Dp

= incremental pressure, bar

DT

= incremental temperature, °C

V

= pipeline fill volume, m³

D

= pipeline outside diameter, m

E

= Young’s elastic modulus of steel, bar

t

= pipe wall thickness, m

n

= Poisson ratio, -

B

= bulk modulus of water, bar

G

= volumetric expansion of water, °C-1

a

= linear expansion of steels, °C-1

By comparison of the incremental volume changes due to pressure and temperature fluctuations over the leak test hold period, the acceptability of the test can be established. In the event of there being any doubt after evaluation of the hold period, the test should be extended until such time as the acceptability is adequately demonstrated or alternatively the presence of a leak is confirmed. In the latter event the leak has to be located and removed from the pipeline prior to retesting. For reference values of the bulk modulus and volumetric expansion of both fresh water and sea water are given in Figures 9 to 12.

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FIGURE-9 BULK MODULUS OF FRESH WATER AS A FUNCTION OF PRESSURE AND TEMPERATURE

FIGURE-10 BULK MODULUS OF SEA WATER AS A FUNCTION OF PRESSURE AND TEMPERATURE

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FIGURE-11 VOLUMETRIC EXPANSION COEEFICIENT OF FRESH WATER AS A FUNCTIONAL OF PRESSURE AND TEMPERATURE

FIGURE-12 VOLUMETRIC EXPANSION COEEFICIENT OF SEA WATER AS A FUNCTIONAL OF PRESSURE AND TEMPERATURE

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2.21.5 Location of Leaks during Hydrostatic Testing While the incidence of leakages/failures during hydrostatic testing is relatively low, its occurrence can cause considerable delays and additional costs. To minimise potential delay and cost it is prudent to formulate a contingency plan at an early stage in the project which can be swiftly put into action if required. Such a contingency plan could, for example, include the addition of a dye to the test water in an offshore pipeline so that in the event of a leak occurring it would not become necessary to refill the pipeline with water containing dye. A variety of techniques are available for locating leaks both in onshore and offshore pipelines. Below Table summarises the presently available techniques together with some pertinent information. Table 2.21.5 - Summary of methods for the location of leaks during hydrostatic:

2.21.6 Testing After New Construction (a) Systems or Parts of Systems (1)

All liquid transportation piping systems within the scope of this Code, regardless of stress, shall be tested after construction. Carbon dioxide systems shall be hydrostatically tested.

(2)

Systems to be operated at a hoop stress of more than 20% of the specified minimum yield strength of the pipe shall be hydrostatically tested.

(3)

Systems to be operated at a hoop stress of 20% or less of specified minimum yield strength of the pipe may be subjected to a leak test in lieu of the hydrostatic test.

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(4)

When testing piping, in no case shall the test pressure exceed that stipulated in the standards of material specifications (except pipe) incorporated.

(5)

Equipment not to be subjected to test pressure shall be disconnected from the piping or otherwise isolated. Valves may be used if valve, including closing mechanism, is suitable for the test pressure.

(b)

Testing Tie-h. Because it is sometimes necessary to divide a pipeline into test sections and install test heads, connecting piping, and other necessary appurtenances for testing, or to install a pre-tested replacement section, it is not required that tie-in welds be tested; however, tie-in welds and girth welds joining lengths of pre-tested pipe shall be inspected by radiographic or other accepted nondestructive methods if system is not pressure tested after tie-in. After such inspection, the joint shall be coated and inspected before backfilling.

(c)

Testing Controls and Protective Equipment. All controls and protective equipment, including pressure limiting devices, regulators, controllers, relief valves, and other safety devices, shall be tested to determine that they are in good mechanical condition; of adequate capacity, effectiveness, and reliability of operation for the service in which they are employed; functioning at the correct pressure; and properly installed and protected from foreign materials or other conditions that might prevent proper operation.

2.21.7 Hydrostatic Testing of Internal Pressure Piping (a)

Portions of piping systems to be operated at a hoop stress of more than 20% of the specified minimum yield strength of the pipe shall be subjected at any point to a hydrostatic proof test equivalent to not less than 1.25 times the internal design pressure at that point for not less than 4 hr. When lines are tested at pressures that develop a hoop stress, based on nominal wall thickness, in excess of W% of the specified minimum yield strength of the pipe, special care shall be used to prevent overstrain of the pipe. (1)

Those portions of piping systems where all of the pressured components are visually inspected during the proof test determine that here is no leakage require no further test. This can include lengths of pipe that are pre-tested for user’s replacement sections.

(2)

On those portions of piping systems not visually inspected while under test, the proof test shall be followed by a reduced pressure leak test equivalent to not less than 1.1 times the internal design pressure for not less than 4 hr.

(b) API RP 11 10 may be used for guidance for the hydrostatic test. (c)

The hydrostatic test shall be conducted with water, except liquid petroleum that does not vaporize rapidly may be used provided: (1)

The pipeline section under test is not offshore and is outside of cities and other populated areas, and each building within 300 ft (90 m) of the test section is unoccupied while the test pressure is equal to or greater than a pressure which produces a hoop stress of 50% of the specific minimum yield strength of the pipe;

(2)

The test section is kept under surveillance by regular patrols during test; and

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Communication is maintained along the test section.

(d)

If the testing medium in the system will be subject to thermal expansion during the test, provisions shall be made for relief of excess pressure. Effects of temperature changes shall be taken into account when interpretations are made of recorded test pressures.

(e)

After completion of the hydrostatic test, it is important in cold weather that the lines, valves, and fittings be drained completely of any water to avoid damage due to freezing.

(f)

Carbon dioxide pipelines, valves, and fittings shall be dewatered and dried prior to placing in service to prevent the possibility of forming a corrosive compound from carbon dioxide and water.

2.21.8 Testing of Fabricated Items (a) Fabricated items such as scraper traps, manifolds, volume chambers, etc., shall be hydrostatically tested to limits equal to or greater than those required of the completed system. This test may be conducted separately or as a part of the completed system.

2.21.9 Testing of Replacement Pipe Sections. When a scheduled repair to a pipeline is made by cutting out a section of the pipe as a cylinder and replacing it with another section of pipe, the replacement section of pipe shall be subjected to a pressure test. The tests may be made on the pipe prior to installation provided radiographic or other acceptable nondestructive tests (visual inspection excepted) are made on all tie in butt welds after installation.

Approved:2009

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