pdfslide.net introduction-to-offshore-pipelines-risers-jaeyoung-lee

Introduction to
Offshore Pipelines and Risers
2007
Jaeyoung Lee, P.E.
-
Introduction to Offshore Pipelines and Risers
PREFACE
This lecture note is prepared to introduce how to design and install offshore
petroleum pipelines and risers including terminologies, general requirements, key
considerations, etc. The author’s nearly twenty years of experience on offshore
pipelines and risers along with the enthusiasm to share his knowledge have aided
the preparation of this note. Readers are encouraged to refer to the references
listed at the end of each section for more information.
Unlike other text books, many pictures and illustrations are enclosed in this note to
assist the readers’ understanding. It should be noted that some pictures and
contents are borrowed from other companies’ websites and brochures. Even
though the exact sources are quoted and listed in the references, please use this
note for engineering education purposes only.
2007
Jaeyoung Lee, P.E.
-4-
TABLE OF CONTENTS
1
INTRODUCTION............................................................................................................... 5
2
REGULATIONS AND PIPELINE PERMITS.................................................................... 13
3
PIPELINE ROUTE SELECTION AND SURVEY............................................................. 17
4
DESIGN PROCEDURES AND DESIGN CODES........................................................... 25
5
FLOW ASSURANCE....................................................................................................... 35
6
UMBILICAL LINE ............................................................................................................ 39
7
PIPE MATERIAL SELECTION........................................................................................ 45
8
PIPE COATINGS ............................................................................................................ 57
9
PIPE WALL THICKNESS DESIGN................................................................................. 67
10
THERMAL EXPANSION DESIGN .................................................................................. 77
11
PIPELINE ON-BOTTOM STABILITY DESIGN ............................................................... 83
12
PIPELINE FREE SPAN ANALYSIS ................................................................................ 87
13
CATHODIC PROTECTION DESIGN .............................................................................. 90
14
PIPELINE INSTALLATION.............................................................................................. 95
15
SUBSEA TIE-IN METHODS ......................................................................................... 107
16
UNDERWATER WORKS .............................................................................................. 121
17
OFFSHORE PIPELINE WELDING ............................................................................... 123
18
PIPELINE PROTECTION – TRENCHING AND BURIAL ............................................. 129
19
PIPELINE SHORE APPROACH AND HDD.................................................................. 137
20
RISER TYPES............................................................................................................... 141
21
RISER DESIGNS .......................................................................................................... 145
22
COMMISSIONING AND PIGGING ............................................................................... 149
23
INSPECTION ................................................................................................................ 155
24
PIPELINE REPAIR........................................................................................................ 159
DEFINITIONS........................................................................................................................ 167
-5-
1
INTRODUCTION
Deepwater means water depths greater than 1,000 ft or 305 m by US MMS (Minerals
Management Service) definition. Deepwater developments outrun the onshore and
shallow water field developments. The reasons are:
•
Limited onshore gas/oil sources (reservoirs)
•
Relatively larger (~20 times (oil) and 8 times (gas)) offshore reservoirs than onshore
•
More investment cost (>~20 times) but more returns
•
Improved geology survey and E&P technologies
A total of 175,000 km (108,740 mi.) or 4.4 times of the earth’s circumference of subsea
pipelines have been installed. The deepest flowline installed is 2,743 m (9,000 ft) in the
Gulf of Mexico (GOM). The longest oil subsea tieback flowline length is 43.4 miles (69.8
km) from the Shell’s Penguin A-E and the longest gas subsea tieback flowline length is
74.6 miles (120 km) of Norsk Hydro’s Ormen Lange, by 2006 [1]. The deepwater
flowlines are getting high pressures and high temperatures (HP/HT). Currently, subsea
systems of 15,000 psi and 350oF (177oC) have been developed. By the year 2005,
Statoil’s Kristin Field in Norway holds the HP/HT record of 3,212 psi (911 bar) and 333oF
(167oC), in 1,066 ft of water.
The deepwater exploration and production (E&P) is currently very active in West Africa
which occupies approximately 40% of the world E&P (see Figure 1.1).
Figure 1.1 Worldwide Deepwater Exploration and Production [1]
North Sea
3%
North America
25%
Africa
40%
Asia
10%
Australasia
2%
Latin America
20%
-6Offshore field development normally requires four elements as below and as shown in
Figure 1.2. Each element (system) is briefly described in the following sub-sections.
•
Subsea System
•
Flowline/Pipeline/Riser System
•
Fixed/Floating Structures
•
Topside Processing System
Figure 1.2 Offshore Field Development Components
Processing
Subsea
Fixed/Floating
Structures
FL/PL/Riser
If the wellhead is located on the seafloor, it is called a wet tree; if the wellhead is located
on the surface structure, it is called a dry tree. Wet trees are commonly used for subsea
tiebacks using long flowlines to save cycle time (sanction to first production). Dry trees
are useful for top tension risers (TTRs) or fixed platform risers and provide reliable well
control system, low workover cost, and better maintenance.
-7-
1.1
Subsea System
The subsea system can be broken into three parts as follows:
•
Wellhead
•
Controls
•
Flowline Connection
Figure 1.1.1 Subsea System
Controls
Wellhead
Mudline
Drilling casing
Flowline
Connection
Wellhead
Wellhead (typically 28-in. diameter) is a topside structure of the drilling casing (typically
36-in. diameter) above the mudline, which is used to mount a Christmas tree (control
panel with valves).
The control system includes a subsea control module (SCM), umbilical termination
assembly (UTA), flying leads, and sensors. SCM is a retrievable component used to
control chokes, valves, and monitor pressure, temperature, position sensing devices,
etc. that is mounted on the tree and/or manifold. UTA allows the use of flying leads to
control equipment. Flying leads connect UTAs to subsea trees. Sensors include sand
detectors, erosion detectors, pig detectors, etc.
For details on flowline connection, please see Subsea Tie-in Methods in Section 15.
-8-
1.2
Flowline/Pipeline/Riser System
Oil was transported by wooden barrels until 1870s. As the volume
was increased, the product was transported by tank cars or trains
and eventually by pipelines. Although oil is sometimes shipped in 55
(US) gallon drums, the measurement of oil in barrels is based on 42
(US) gallon wooden barrels of the 1870s.
Flowlines transport unprocessed fluid – crude oil or gas. The conveyed fluid can be a
multi-phase fluid possibly with paraffin, asphaltene, and other solids like sand, etc. The
flowline is sometimes called a “production line” or “import line”. Most deepwater
flowlines carry very high pressure and high temperature (HP/HT) fluid.
Pipelines transport processed oil or gas. The conveyed fluid is a single phase fluid after
separation from oil, gas, water, and other solids. The pipeline is also called an “export
line”. The pipeline has moderately low (ambient) temperature and low pressure just
enough to export the fluid to the destination. Generally, the size of the pipeline is greater
than the flowline.
It is important to distinguish between flowlines and pipelines since the required design
code is different. In America, the flowline is called a “DOI line” since flowlines are
regulated by the Department of Interior (DOI 30 CFR Part 250: Code of Federal
Regulations). And the pipeline is called a “DOT line” since pipelines are regulated by the
Department of Transportation (DOT 49 CFR Part 195 for oil and Part 192 for gas).
-9-
1.3
Fixed/Floating Structures
The transported crude fluids are normally treated by topside processing facility at the
water surface, before being sent to the onshore refinery facilities. If the water depth is
relatively shallow, the surface structure can be fixed on the sea floor. If the water depth
is relatively deep, the floating structures moored by tendons or chains are recommended
(see Figure 1.3.1).
Fixed platforms, steel jacket or concrete gravity platform, are installed in up to 1,353 ft
water depth (Shell Bullwinkle). Four (4) compliant piled towers (CPTs) have been
installed worldwide in water depths 1,000 ft to 1,754 ft. It is known that the material and
fabrication costs for CPT are lower but the design cost is higher than conventional fixed
jacket platform.
Tension leg platforms (TLPs) have been installed in water depths 482 ft to 4,674 ft
(ConocoPhillips’ Magnolia).
Spar also called DDCV (deep draft caisson vessel), DDF (deep draft floater), or SCF
(single column floater) is originally invented by Deep Oil Technology (later changed to
Spar International, a consortium between Aker Maritime (later Technip) and J. Ray
McDermott (later FloaTEC)). Total 16 spars, including 15 in GOM, have been installed
worldwide in water depths 1,950 ft to 5,610 ft (Dominion’s Devils Tower).
Semi-Floating Production Systems (semi-FPSs) or semi-submersibles have been
installed in water depths ranging from 262 ft to 7,920 ft (Anadarko’s Independence Hub).
Floating production storage and offloading (FPSO) has advantages for moderate
environment with no local markets for the product, no pipeline infra areas, and short life
fields. No FPSO has been installed in GOM, even though its permit has been approved
by MMS. FPSOs have been installed in water depths between 66 ft to 4,796 ft (Chevron
Agbami).
Floating structure types should be selected based on water depth, metocean data,
topside equipment requirements, fabrication schedule, and work-over frequencies.
Table 1.3.1 shows total number of deepwater surface structures installed worldwide by
2006. Subsea tieback means that the production lines are connected to the existing
subsea or surface facilities, without building a new surface structure. The advantages of
the subsea tiebacks are lower capital cost and shorter cycle time by 70% (sanction to
first production) compared to implementing new surface structure.
- 10 -
Table 1.3.1 Number of Surface Structures Worldwide [2]
Structure Types
No. of
Structures
Fixed Platforms (WD>1,000’)
~6,000
Water Depths
(ft)
40 - 1,353
Compliant Towers
4
1,000 – 1,754
TLPs
23
482 - 4,674
Spars
16
1,950 - 5,610
Semi-FPSs (Semi-submersibles)
43
262 – 7,920
FPSOs
148
66 – 4,796
3,622
49 – 7,600
Subsea Tiebacks
Figure 1.3.1 Fixed & Floating Structures [3]
Fixed Platform
Compliant Tower
TLP
Mini-TLP
Spar
Semi-FPS
FPSO
- 11 -
1.4
Topside Processing System
As mentioned earlier, the crude is normally treated by topside processing facilities before
being sent to the onshore. Due to space and weight limit on the platform deck, topside
processing facility is required to be compact, so its design is more complicated than that
of an onshore process facility.
Requirements on topside processing systems depend on well conditions and future
extension plan. General topside processing systems required for typical deepwater field
developments are:
•
Well control unit
•
Hydraulic power unit (HPU)
•
Uninterruptible power supply (UPS)
•
Control valves
•
Multiphase meter
•
Umbilical termination panel
•
Crude oil separation
•
Emulsion breaking
•
Pumping and metering system
•
Heat exchanger (crude to crude and gas)
•
Electric heater
•
Gas compression
•
Condensate stabilization unit
•
Subsea chemical injection package
•
Pigging launcher and receiver
•
Pigging pump, etc.
- 12 References
[1]
SUT (Society for Underwater Technology) Subsea Tieback (SSTB) Workshop,
Galveston, Texas, 2007
[2]
2006 Deepwater Solutions & Records for Concept Selection, Offshore Magazine
Poster
[3]
www.mms.gov, Minerals Management Service website, U.S. Department of the
Interior
[4]
Offshore Engineering - An Introduction, Angus Mather, Witherby & Company
Limited, 1995
[5]
Offshore Pipeline Design, Analysis and Methods, Mouselli, A.H., Penn Well
Books, 1981
[6]
Offshore Pipelines, Guo, Boyun, et. al, Elsevier, 2005
[7]
Pipelines and Risers, Bai, Y., Elsevier, 2001
[8]
Deepwater Petroleum Exploration and Production, Leffler, W.L., et. al., Penn
Well Books, 2003
[9]
Petroleum Production Systems, Economides, Michael, et. al., Prentice Hall
Petroleum Engineering Series
- 13 -
2
REGULATIONS AND PIPELINE PERMITS
Prior to conducting drilling operations, the operator is required to submit and obtain
approval for an Application for Permit to Drill (APD) from the authorities. The APD
requires detailed information about the drilling program for evaluation with respect to
operational safety and pollution prevention measures. Other information including
project layout, design criteria for well control and casing, specifications for blowout
preventors, and a mud program is required.
The developer must design, fabricate, install, use, inspect, and maintain all platforms
and structures to assure their structural integrity for the safe conduct of operations at
specific locations. Factors such as waves, wind, currents, tides, temperature, and the
potential for marine growth on the structure are to be considered.
All surface production facilities including separators, treaters, compressors, and headers
must be designed, installed, and maintained to assure the safety and protection of the
human, marine, and coastal environments.
In the USA, the regulatory processes and jurisdictional authority concerning pipelines on
the Outer Continental Shelf (OCS) and in coastal areas are shared by several federal
agencies, including the Department of Interior (DOI), the Department of Transportation
(DOT), U.S. Army Corps of Engineers (COE), the Federal Energy Regulatory
Commission (FERC), and U.S. Coast Guard (USCG) [1].
The DOT is responsible for regulating the safety of interstate commerce of natural gas,
liquefied natural gas (LNG), and hazardous liquids by pipeline. The regulations are
contained in 49 CFR Part 192 (for gas pipeline) and part 195 (for oil pipeline)
(References [2] & [3]). The DOT is responsible for all transportation pipelines beginning
downstream of the point at which operating responsibility transfers from a producing
operator to a transporting operator.
The DOI’s responsibility extends upstream from the transfer point described above. The
MMS is responsible for regulatory oversight of the design, installation, and maintenance
of OCS oil and gas pipelines (flowlines). The MMS operating regulations for flowlines are
found at 30 CFR Part 250 Subpart J [4].
- 14 Pipeline permit applications to regulatory authorities include the pipeline location
drawing, profile drawing, safety schematic drawing, pipe design data to scale, a shallow
hazard survey report, and an archaeological report (if required). The proposed pipeline
routes are evaluated for potential seafloor, subsea geologic hazards, other natural or
manmade seafloor, and subsurface features/conditions including impact from other
pipelines.
Routes are also evaluated for potential impacts on archaeological resources and
biological communities. A categorical exclusion review (CER), environmental
assessment (EA), and/or environmental impact statement (EIS) should be prepared in
accordance with applicable policies and guidelines.
The design of the proposed pipeline is evaluated for:
•
•
•
•
•
•
•
Appropriate cathodic protection system to protect the pipeline from leaks resulting
from the external corrosion of the pipe;
External pipeline coating system to prolong the service life of the pipeline;
Measures to protect the inside of the pipeline from the detrimental effects, if any, of
the fluids being transported;
Pipeline on-bottom stability (that is, that the pipeline will remain in place on the
seafloor and not float);
Proposed operating pressures;
Adequate provisions to protect other pipelines the proposed route crosses over; and
Compliance with all applicable regulations.
According to MMS regulations (30 CFR Part 250), pipelines with diameters less than 85/8 inches installed in water depths less than 200 ft are to be buried to a depth of at least
3 ft below the mudline. If the MMS determines that the pipeline may constitute a hazard
to other uses, all pipelines (regardless of pipe size) installed in water depths less than
200 ft must be buried. The purpose of these requirements is to reduce the movement of
pipelines by high currents and storms, to protect the pipeline from the external damage
that could result from anchors and fishing gear, to reduce the risk of fishing gear
becoming snagged, and to minimize interference with the operations of other users of
the OCS. For pipe sizes less than 8-5/8 inches, the burial requirement may be waived if
the line is to be laid on a soft soil which will allow the pipeline to sink into the sediments
(self-burial). Any pipeline crossing a fairway or anchorage in federal waters must be
buried to a minimum depth of 10 ft below mudline across a fairway and a minimum depth
of 16 ft below mudline across an anchorage area.
- 15 References
[1]
OCS Report MMS 2001-067, Brief Overview of Gulf of Mexico OCS Oil and Gas
Pipelines: Installation, Potential Impact, and Mitigation Measures, Minerals
Management Service, U.S. Department of the Interior, 2001
[2]
49 CFR, Part 192, Transportation of Natural and Other Gas by Pipeline:
Minimum Federal Safety Standards
[3]
49 CFR, Part 195, Transportation of Hazardous Liquids by Pipeline
[4]
30 CFR, Part 250, Oil and Gas and Sulfur Operations in the Outer Continental
Shelf
- 16 -
- 17 -
3
PIPELINE ROUTE SELECTION AND SURVEY
When layout the field architecture, several considerations should be accounted for:
•
•
•
•
•
•
Compliance with regulation authorities and design codes
Future field development plan
Environment, marine activities, and installation method (vessel availability)
Overall project cost
Seafloor topography
Interface with existing subsea structures
The pipeline route should be selected considering:
•
•
•
•
•
•
•
•
•
•
Low cost (select the most direct and shortest P/L route)
Seabed topography (faults, outcrops, slopes, etc.)
Obstructions, debris, existing pipelines or structures
Environmentally sensitive areas (beach, oyster field, etc.)
Marine activity in the area such as fishing or shipping
Installability (1st end initiation and 2nd end termination)
Required pipeline route curvature radius
Riser hang-off location at surface structure
Riser corridor/clashing issues with existing risers
Tie-in methods
The required minimum pipeline route curve radius (Rs) should be determined to prevent
slippage of the curved pipeline on the sea floor while making a curve, in accordance with
the following formula [1]. If the pipeline-soil friction resistance is too small, the pipeline
will spring-back to straight line. The formula also can be used to estimate the required
minimum straight pipeline length (Ls), before making a curve, to prevent slippage at
initiation. If Ls is too short, the pipeline will slip while the curve is being made.
Rs = Ls =
F TH
Ws µ
Where,
Rs =
Ls =
F=
TH =
Ws =
Min. non-slippage pipeline route curve radius
Min. non-slippage straight pipeline length
Safety factor (~2.0)
Horizontal bottom tension (residual tension)
Pipe submerged weight
µ=
lateral pipeline-soil friction factor (~0.5)
- 18 If a 16” OD x 0.684” WT pipe is installed in 3,000 ft of water depth using a J-lay method
(assuming a catenary shape), the bottom tension and the Rs and Ls can be estimated as
follows:
The submerged pipe weight, Ws = 22.6 lb/ft
Assuming the pipe departure angle (α) at J-lay tower as10 degrees
Top tension, T = Ws x WD / (1- sin α) = 22.6 x 3,000 / (1- sin 10) = 82,047 lb ∼ 82 kips
Bottom tension, TH = T x sin α = 82 x sin 10 = 14.2 kips
Rs = Ls =
F TH 2.0 × 14.2 × 1,000
=
= 2,513 ft ∴ Use minimum 3,000 ft
Ws µ
22.6 × 0.5
Initiation
point
Ls
Rs
α
Lay direction
If the curvature angle (α) and the pipe rigidity (elastic stiffness = elastic modulus (E) x
pipe moment of inertia (I)) are considered to do a big role on the Rs and Ls estimates, the
above formula can be modified as follows:
Rs = Ls =
F TH
EI
+ 2
Ws µ
R (1 - cos α )
Once the field layout and pipeline route is determined by desktop study using an existing
field map, the pipeline route survey is contracted to obtain site-specific information
including bathymetry, seabed characteristics, soil properties, stratigraphy, geohazards,
and environmental data.
- 19 Bathymetry (hydrographic) survey using echo sounders provides water depths (sea
bottom profile) over the pipeline route. The new technology of 3-D bathymetry map
shows the sea bottom configuration more clearly than the 2-D bathymetry map (see
Figure 3.1).
Figure 3.1 Sample of Bathymetry Map
2D View
3-D View
Side scan sonar is the industry standard method of providing high resolution mapping of
the seabed. It uses narrow beams of acoustic energy (sound) which is transmitted out to
the seabed topography (or objects within the water column) and reflected back to the
towfish. It is used to identify obstructions, outcrops, faults, debris, pockmarks, gas
vents, anchor scars, pipelines, etc. Typically objects larger than 1m are accurately
located and measured (see Figure 3.2).
Figure 3.2
Side Scan Sonar Interpretation [2] B
- 20 An acoustic sub-bottom profiler is a tool to measure geological characteristics i.e.
subsurface strata (stratigraphy), faults, sediment thickness, etc. Figure 3.3 shows one
example of sub-bottom profile and its interpretation.
Figure 3.3 Sub-bottom Profile [2]
Magnetometer (Figure 3.4) is a tool to locate cables, anchors, pipelines, and other
metallic objects. It is near-bottom towed by a cable from a survey vessel.
Figure 3.4 Geometrics G-882 Magnetometer [3]
- 21 Soil sampling is required to calibrate and quantify geophysical and geotechnical
properties of soils. The soil sampling instruments include grabs, gravity drop corers, and
vibracorers. Drop corer or gravity corer is a device which is ‘dropped’ off from a survey
vessel. And on contact with the seabed, a piston in the device is activated and takes a
shallow ‘core’ (up to a meter or so in depth). This core is retained and preserved in the
device and then hauled back to the surface. The core samples collected are
photographed, logged, tested (by either Torvane or mini cone penetrometer) and
sampled onboard the survey vessel. Further sampling and geotechnical testing can be
undertaken in the laboratory. The cone penetration test (CPT) provides tip resistance,
sleeve friction, friction ratio, undrained shear strength, and relative density. Figures 3.5
and 3.6 show drop corer and Torvane shear test kit.
Figure 3.5 Drop Corer [4]
Wireline to surface
Release
mechanism
Weights
(400-800 lbs)
Barrel
(10-20 ft)
Core
catcher
Weight triggering
release mechanism
on hitting seafloor
- 22 -
Figure 3.5 Torvane Shear Test Kit [5]
Environmental (metocean) data including wind, waves, and current along the water
depth for 1, 5 (2 or 10), and 100 year return periods are required.
- 23 References
[1] Pipeline Manual, Chevron, 1994
[2] EGS Survey Website, http://egssurvey.com/enter_ser.htm
[3] Geometrics Website, http://geometrics.com/magnetometers/Marine/G-882/g882.html
[4] Submarine Pipeline On-bottom Stability Analysis and Design Guidelines, AGA,
1993
[5] Earth Manual, U.S. Department of the Interior, 1998, or
http://www.usbr.gov/pmts/writing/earth/earth.pdf
[6] Simon A. Bonnel, et. al., Pipeline Routing and Engineering for Ultra-Deepwater
Developments, OTC (Offshore Technology Conference) Paper No. 10708, 1999
- 24 -
- 25 -
4
DESIGN PROCEDURES AND DESIGN CODES
There are typically three phases in offshore pipeline designs: conceptual study (or PreFEED: front end engineering & design), preliminary design (or FEED), and detail
engineering.
•
Conceptual study (Pre-FEED) – defines technical feasibility, system constraints,
required information for design and construction, rough schedule and cost estimate
•
Preliminary design (FEED) – defines pipe size and grade to order pipes and
prepares permit applications.
•
Detail engineering – defines detail technical input to prepare procurement and
construction tendering.
The pipeline design procedures may vary depending on the design phases above.
Tables 4.1 and 4.2 show a flowchart for preliminary design phase and detail engineering
phase, respectively.
Design basis is an on-going document to be updated as needed as the project proceeds,
especially in conceptual and preliminary design phases. The design basis should
contain:
•
•
•
•
•
•
•
•
•
•
•
•
•
Pipe Size
Design Pressure (@ wellhead or platform deck)
Design Temperature
Pressure and Temperature Profile
Max/Min Water Depth
Corrosion Allowance
Required overall heat transfer coefficient (OHTC) Value
Design Code (ASME, API, or DNV)
Installation Method (S, J, Reel, or Tow)
Metocean Data
Soil Data
Design Life, etc.
Fluid property (sweet or sour)
- 26 -
Table 4.1 Preliminary Design (FEED) Flowchart
Scope of Work
Route Selection
Design Basis
Pipe Material
Selection
Hazard Survey
Pipe WT
Determination
Preliminary Cost
Estimate
Flow Assurance
Pipe Coating
Selection
Preliminary Design
Drawings
Thermal
Expansion
Procurement Long
Lead Items
Permit
On-bottom
Stability
Free Span
Cathodic
Protection
Tie-ins and Shore
Approach
Installation Check
- 27 -
Table 4.2 Detail Engineering Flowchart
Scope of Work
Design Basis
Route Selection
Metallurgy &
Welding Study
Pipe WT and
Grade Check
Material/Construction
Specifications
Pipe Coating
Selection
Construction
Drawings
Thermal
Expansion
Procurement &
Construction Support
Route Survey
Flow Assurance
On-bottom
Stability
Free Span
Cathodic
Protection
Tie-ins and Shore
Approach
Installation Check
- 28 The following international codes, standards, and regulations are used for the design of
offshore pipelines and risers.
US Code of Federal Regulations (CFR)
30 CFR, Part 250
Oil and Gas and Sulfur Operations in the Outer Continental Shelf
49 CFR, Part 192
Transportation of Natural and Other Gas by Pipeline: Minimum
Federal Safety Standards
49 CFR, Part 195
Transportation of Hazardous Liquids by Pipeline
American Bureau of Shipping (ABS)
ABS
Fatigue Assessment of Offshore Structures
ABS
Guide for Building & Classing; Subsea Pipeline Systems
ABS
Guide for Building & Classing; Subsea Riser Systems
ABS
Guide for Building and Classing; Facilities on Offshore Installations
ABS
Rules for Building and Classing; Offshore Installations
ABS
Rules for Building and Classing; Single Point Moorings
ABS
Rules for Certification of Offshore Mooring Chain
American Petroleum Institute (API)
API Bull 2U
API Bulletin on Stability Design of Cylindrical Shells, 2004
API 17J
Specification for Unbonded Flexible Pipe, 2002
API 598
Standard Valve Inspection and Testing
API 600
Cast Steel Gates, Globe and Check Valves
API 601
Metallic Gaskets for Refinery Piping (Spiral Wound)
API RP 2A
Recommended Practice for Planning, Designing and Constructing
Fixed Offshore Platforms - Working Stress Design
API RP 2RD
Design of Risers for Floating Production Systems (FPSs) and
Tension-Leg Platforms (TLPs), First Edition, 1998
API RP 5LW
Recommended Practice for Transportation of Line Pipe on Barges
and Marine Vessels
API RP 5L1
Recommended Practice for Railroad Transportation of Line Pipe
API RP 5L5
Recommended Practice for Marine Transportation of Line Pipe
API RP 6FA
Specification for Fire Test for Valves
API RP 14E
Recommended Practice for Design and Installation of Offshore
Production Platform Piping Systems - Risers
API RP 17A
Recommended Practice for Design and Operation of Subsea
Production Systems – Pipelines and End Connections
API RP 17B
Recommended Practice for Flexible Pipe, 1998
- 29 API RP 500C
Classification of Locations for Electrical Installation at Pipeline
Transportation Facilities
API RP 1110
Pressure Testing of Liquid Petroleum Pipelines, 1997
API RP 1111
Recommended Practice for Design Construction, Operation, and
Maintenance of Offshore Hydrocarbon Pipelines, 1999
API RP 1129
Assurance of Hazardous Liquid Pipeline System Integrity
API Spec 2B
Specification for Fabricated Structural Steel Pipe
API Spec 2W
Specification for Steel Plates for Offshore Structures, Produced by
Thermo-Mechanical Control Processing (TMCP).
API Spec 2C
Offshore Cranes
API Spec 2Y
Specification for Steel Plates, Quenched and Tempered, for
Offshore Structures
API Spec 5L
Specification for Line Pipe
API Spec 6D
Specification for Pipeline Valves (Gate, Ball, and Check Valves)
API Spec 6H
Specification for End Closures, Connectors and Swivels
API Std 1104
Standard for Welding of Pipelines and Related Facilities
American Society of Mechanical Engineers (ASME)
ASME B16.5
Steel Pipe Flanges and Flanged Fittings
ASME B16.9
Factory Made Wrought Steel Butt Welding Fittings
ASME B16.10
Face-to-Face and End-to-Ends Dimensions of Valves
ASME B16.11
Forged Steel Fittings, Socket Welding and Threaded
ASME B16.20
Ring Joints, Gaskets and Grooves for Steel Pipe Flanges
ASME B16.25
Butt Welded Ends for Pipes, Valves, Flanges and Fittings
ASME B16.34
Valves - Flanged, Threaded, and Welding End
ASME B16.47
Large Diameter Steel Flanges - NPS 26 through NPS 60
ASME B31.3
Chemical Plant and Petroleum Refinery Piping
ASME B31.4
Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum
Gas, Anhydrous Ammonia and Alcohols, 1999
ASME B31.8
Gas Transmission and Distribution Piping Systems, 1999
ASME II
Materials
ASME V
Non-Destructive Examination
ASME VIII, Div 1&2
Rules for Construction of Pressure Vessels
ASME IX
Welding and Brazing Qualifications
- 30 -
American Society of Testing and Materials (ASTM)
ASTM A6
Standard Specification for General Requirements for Rolled Steel
Plates, Shapes, Sheet Piling, and Bars for Structural Use
ASTM A20/20M
General requirements for Steel Plates for Pressure Vessels
ASTM A36
Standard Specification for Carbon Structural Steel
ASTM A53
Standard Specification for Steel Castings, Ferritic and Martensitic,
for Pressure-Containing Parts, Suitable for Low-Temperature
Service
ASTM A105
Standard Specification for Carbon Steel Forgings for Piping
Applications
ASTM A185
Specification for Welded Wire Fabric, Plain for Concrete
Reinforcement
ASTM A193
Standard Specification for Alloy-Steel and Stainless Steel Bolting
Materials for High Temperature or High Pressure Service and Other
Special Purpose Applications
ASTM A194
Standard Specification for Carbon and Alloy Steel Nuts for Bolts for
High Pressure or High Temperature Service, or Both
ASTM A234
Standard Specification for Piping Fittings of Wrought Carbon Steel
and Alloy Steel for Moderate and High Temperature Service
ASTM A283
Low and Intermediate Tensile Strength Carbon Steel Plates,
Shapes and Bars
ASTM A307
Standard Specification for Carbon Steel Bolts and Studs
ASTM A325
Standard Specification for Structural Bolts, Steel, Heat Treated,
120/150 ksi Minimum Tensile Strength
ASTM A490
Standard Specification for Heat Treated-Treated Steel Structural
Bolts 150 ksi Minimum Tensile Strength
ASTM A500
Cold Formed Welded and Seamless Carbon Steel Structural
Tubing in Rounds and Shapes
ASTM A615
Specification for Deformed Billet-Steel ars for Concrete
Reinforcement
ASTM B418
Cast and Wrought Galvanized Zinc Anodes (Type II)
American Welding Society (AWS)
AWS D1.1
Structural Welding Code – Steel
- 31 -
British Standard (BS)
BS 4515
Appendix J. Process of Welding of Steel Pipelines on Land and
Offshore– Recommendations for Hyperbaric Welding
BS 7608
Code of Practice for Fatigue Design and Assessment of Steel
Structures, 1993, British Standard Institution
BS 8010-2
Code of Practice for Pipelines - Subsea Pipelines, 2004, British
Standard Institution
Canadian Standards Association (CSA)
CSA-Z187
Offshore Pipelines
Det Norske Veritas (DNV)
DNV
Rules for Design, Construction and Inspection of Offshore
Structures.
DNV
Rules for Planning and Execution of Marine Operations - Part 1
General
DNV
Rules for Planning and Execution of Marine Operations - Part 2
Operation Specific Requirements
DNV-CN-30.2
Fatigue Strength Analysis for Mobile Offshore Units
DNV-CN-30.4
Foundations
DNV-CN-30.5
Environmental Conditions and Environmental Loads
DNV-OS-B101
Metallic Materials
DNV-OS-C101
Design of Offshore Steel Structures, General (LRFD method)
DNV-OS-C106
Structural Design of Deep Draught Floating Units (LRFD method)
DNV-OS-C201
Structural Design of Offshore Units (WSD method)
DNV-OS-C301
Stability and Watertight Integrity
DNV-OS-C401
Fabrication and Testing of Offshore Structures
DNV-OS-C502
Offshore Concrete Structures
DNV-OS-D101
Marine and Machinery Systems and Equipment
DNV-OS-D201
Electrical Installations
DNV-OS-D202
Instrumentation and Telecommunication Systems
DNV-OS-D301
Fire Protection
DNV-OS-E201
Oil and Gas Processing Systems
DNV-OS-E301
Position Mooring
DNV-OS-E402
Offshore Standard for Diving Systems
DNV-OS-E403
Offshore Loading Buoys
- 32 DNV-OS-F101
Submarine Pipeline Systems, 2003
DNV-OS-F107
Pipeline Protection
DNV-OS-F201
Dynamic Risers, 2001
DNV-OSS-301
Certification and Verification of Pipelines
DNV-OSS-302
Offshore Riser Systems
DNV-OSS-306
Verification of Subsea Facilities
DNV-RP-B401
Cathodic Protection Design, 1993
DNV-RP-C201
Buckling Strength of Plated Structure
DNV-RP-C202
Buckling Strength of Shells
DNV-RP-C203
Fatigue Strength Analysis of Offshore Steel Structures
DNV-RP-C204
Design against Accidental Loads
DNV-RP-E301
Design and Installation of Fluke Anchors in Clay
DNV-RP-E302
Design and Installation of Plate Anchors in Clay
DNV-RP-E303
Geotechnical Design and Installation of Suction Anchors in Clay
DNV-RP-E304
Damage Assessment of Fibre Ropes for Offshore Mooring
DNV-RP-E305
On-bottom Stability Design of Submarine Pipelines, 1988
DNV-RP-F102
Pipeline Field Joint Coating and Field Repair of Linepipe Coating
DNV-RP-F103
Cathodic Protection of Submarine Pipelines by Galvanic Anodes,
2006
DNV-RP-F104
Mechanical Pipeline Couplings
DNV-RP-F105
Free Spanning Pipelines, 2006
DNV-RP-F106
Factory Applied External Pipeline Coatings for Corrosion Control
DNV-RP-F107
Risk Assessment of Pipeline Protection
DNV-RP-F108
Fracture Control for Pipeline Installation Methods Introducing Cyclic
Plastic Strain
DNV-RP-F109
On Bottom Stability of Offshore Pipeline Systems, 2006 Draft
DNV-RP-F111
Interference between Trawl Gear and Pipe-lines
DNV-RP-F202
Composite Risers
DNV-RP-F204
Riser Fatigue, 2005
DNV-RP-F205
Global Performance Analysis of Deepwater Floating Structures
DNV-RP-G101
Risk Based Inspection of Offshore Topside Static Mechanical
Equipment
DNV-RP-H101
Risk Management in Marine and Subsea Operations
- 33 DNV-RP-H102
Marine Operations during Removal of Offshore Installations
DNV-RP-O401
Safety and Reliability of Subsea Systems
DNV-RP-O501
Erosive Wear in Piping Systems
International Organization for Standardization (ISO)
ISO-15589-2
Cathodic Protection of Pipeline Transportation Systems - Part 2:
Offshore Pipelines, 2004, International Organization for
Standardization
Manufacturers Standardization Society (MSS)
MSS SP-44
Steel Pipeline Flanges
MSS SP-75
Specification for High Test Wrought Butt Welding Fittings
National Association of Corrosion Engineers (NACE)
NACE RP-0176-94
Corrosion Control of Steel Fixed Offshore Platforms Associated with
Petroleum Production, 1994
Nobel Denton Industries (NDI)
NDI-0013
General Guidelines for Marine Loadouts
NDI-0027
Guidelines for Lifting Operations by Floating Crane Vessels
NDI-0030
General Guidelines for Marine Transportations
NORSOK Standards
NORSOK G-001
Marine Soil Investigations
NORSOK L-005
Compact Flanged Connections
NORSOK M-501
Surface Preparation and Protective Coating
NORSOK M-506
Corrosion Rate Calculation Model
NORSOK N-001
Structural Design
NORSOK N-004
Design of Steel Structures
NORSOK U-001
Subsea Production Systems
NORSOK UCR-001
Subsea Structures and Piping Systems
Tube & Pipe Association (TPA)
TPA IBS-98
Recommended Standards for Induction Bending of Pipe and Tube,
1998
- 34 -
- 35 -
5
FLOW ASSURANCE
Flow assurance is required to determine the optimum flowline pipe size based on
reservoir well fluid test results for the required flowrate and pressure. As the pipe size
increases, the arrival pressure and temperature decrease. Then, the fluid may not reach
the destination and hydrate, wax, and asphaltene may be formed in the flowline. If the
pipe size is too small, the arrival pressure and temperature may be too high and
resultantly a thick wall pipe may be required and a large thermal expansion is expected.
It is important to determine the optimum pipe size to avoid erosional velocity and
hydrate/ wax/asphaltene deposition. Based on the hydrate/wax/asphaltene appearance
temperature, the required OHTC is determined to choose a desired insulation system
(type, material, and thickness.) If the flowline is to transport a sour fluid containing H2S,
CO2, etc., the line should be chemically treated or a special corrosion resistant alloy
(CRA) pipe material should be used. Alternatively, a corrosion allowance can be added
to the required pipe wall thickness. capital expense (Capex) and operational expense
(opex) using CRA, chemical injection, corrosion allowance, or combination of the above
should be exercised to determine the pipe material and wall thickness.
Figure 5.1 shows various plugged flowlines due to asphaltene, wax, and hydrate
deposition.
Figure 5.1 Plugged Flowlines
(a) Asphaltene
(b) Wax
(c) Hydrate
- 36 Figure 5.2 illustrates one example of how to select pipe size from flow assurance results.
The blue solid line represents inlet pressure at wellhead and the red dotted line
represents outlet fluid temperature. The 8” ID pipe may require a heavy (thick) wall and
the 12” ID pipe may require a thick insulation coating depending on hydrate (wax or
asphaltene) formation temperature.
Figure 5.2 Inlet Pressure & Outlet Temperature vs. Flowline ID
450
70
400
60
350
Temperature(oC)
40
300
250
30
Pressure (bar)
20
200
150
8” ID
100
150
50
170
190
12” ID
10” ID
210
230
Flowline ID (mm)
250
270
290
10
310
0
- 37 References
[1] Properties of Oils and Natural Gases, Pederson, K.S., et. al., Gulf Publishing Inc.,
1989
[2] The Properties of Petroleum Fluids, McCain, William, PennWell Publishing
Company, 1990
[3] “A Comprehensive Mechanistic Model for Two-Phase Flow in Pipelines,” Xiao, J.J.,
Shoham, O., and Brill, J.P., 65th Annual Technical Conference & Exhibition, Society
of Petroleum Engineers, 1990
[4] CRC Handbook of Solubility Parameters and Other Cohesion Parameters, Barton,
A.F.M., CRC Press, 1991
[5] “Prediction of Slug Liquid Holdup – Horizontal to Upward Vertical Flow,” Gomez, L.,
et. al., International Journal of Multiphase Flow, 2000
[6] “Fluid Transport Optimization Using Seabed Separation,” Song, S. and Kouba, G.,
Energy Sources Technology Conference & Exhibition, 2000
[7] PVT and Phase Behaviour of Petroleum Reservoir Fluids, Danesh, Ali, Elsevier
Science B.V., 2001
[8] Mechanistic Modeling of Gas/Liquid Two-Phase Flow in Pipes, Shoham, O.,
Society of Petroleum Engineers, 2006
Standard Temperature and Pressure (STP)
Science:
0oC (273.15oK) and 1 bar (100 kPa)
Oil & Gas Industry:
60oF (15.6oC) and 14.73 psia (30” Ag or 1.0156 bar)
1 bar = 14.504 psi
1 atmosphere = 14.696 psi
- 38 -
- 39 -
6
UMBILICAL LINE
Umbilicals (Figure 6.1) are used to supply electric/hydraulic power to subsea valves/
actuators, receive communication signal from subsea control system, and send
chemicals to treat subsea wells. The functions of umbilicals can be;
•
•
•
•
•
•
•
Chemical Injection
Electric Hydraulic
Electric Power
Hydraulic
Communications
Scale Squeeze
Seismic, etc.
From flow assurance analysis, the type, quantity, and size of each umbilical tube are
determined. Most commonly used chemicals are; scale inhibitor, hydrate inhibitor,
paraffin inhibitor, asphaltene inhibitor, corrosion inhibitor, etc.
The umbilical terminates at subsea umbilical termination assembly (SUTA) and each
function hose or cable connects to manifold or tree by flexible flying leads.
Umbilical manufacturers include; DUCO (formerly Dunlop Coflexip, now a Technip
company), Oceaneering Multiplex, Aker Kvaener, Nexans (formerly Alcatel), JDR, etc.
Figure 6.2 shows Oceaneering’s Panama City plant.
Figure 6.1 Umbilical Lines [1]
- 40 -
Figure 6.2 Oceaneering Umbilical Plant [2]
- 41 -
Figure 6.3 UTA (Umbilical Termination Assembly) Installation [3]
- 42 Bend restrictor (or bend limiter) is commonly found at the end of cables, umbilicals, and
flexible pipes, such as surface termination, subsea Manifold or PLET termination, and in
any region where over bending is a problem. Unlike a bend stiffener, the bend restrictor
does not increase the umbilical or pipe’s stiffness. When the bend restrictor is at "lock
up" radius, it prevents the umbilical or pipe from over bending, kinking, or buckling.
Bend restrictors can be manufactured from polyurethane or steel. The half shell
elements are bolted together around the pipe and the next elements are bolted to
interlock with those already in place. Each element allows to move a small angular
distance and when this distance is projected over the length of the restrictor, the lock up
radius is formed. This radius is to be equal to or greater than the minimum bend radius
of the flexible.
Bending stiffeners are used at the termination point of cables, umbilicals, and flexible
pipes where the stiffness of the system undergoes a step change. This sudden stiffness
change between the flexible and rigid termination structure creates high levels of stress
when the flexible is bent. In a dynamic situation such as repeat bending, this can lead to
fatigue failure in the flexible. Bend stiffeners are utilized to increase the stiffness of the
flexible. The most common method of achieving this is to attach an molded elastomer
tapered sleeve to the flexible.
Figure 6.4 shows bend restrictor and bend stiffness configurations.
Figure 6.4 Bend Restrictor (left) [4] and Bend Stiffener (right) [5]
- 43 References
[1]
Offshore-Technology.com website, www.offshore-technology.com
[2]
Oceaneering International, Inc. website, www.oceaneering.com
[3]
Nexen Aspen Project, presented at Houston Marine Technology Society
luncheon meeting, 2007, www.mtshouston.org
[4]
Dunlaw Engineering Ltd. website, http://www.dunlaw.com/bend_limiters.html
[5]
Trelleborg CRP website, http://www.crpgroup.com/engineered_products.htm
- 44 -
- 45 -
7
PIPE MATERIAL SELECTION
Pipe material type, i.e. rigid, flexible, or composite, should be determined considering:
•
Conveyed fluid properties (sweet or sour) and temperature
•
Pipe material cost
•
Installation cost
•
Operational cost (chemical treatment)
There are several different pipes used in offshore oil & gas transportation as follows:
7.1
•
Low carbon steel pipe
•
Corrosion resistant alloy (CRA) pipe
•
Clad pipe
•
Composite pipe
•
Flexible pipe
•
Flexible hose
•
Coiled tubing
Low Carbon Steel Pipe
Low carbon (carbon content less than 0.29%) steel is mild and has a relatively low
tensile strength so it is used to make pipes. Medium or high carbon (carbon content
greater than 0.3%) steel is strong and has a good wear resistance so they are used to
make forging, automotive parts, springs, wires, etc. Carbon equivalent (CE) refers to
method of measuring the maximum hardness and weldability of the steel based on
chemical composition of the steel. Higher C (carbon) and other alloy elements such as
Mn (manganese), Cr (chrome), Mo (molybdenum), V (vanadium), Ni (nickel), Cu
(copper), etc. tend to increase the hardness (harder and stronger) but decrease the
weldability (less ductile and difficult to weld). The CE shall not exceed 0.43% of total
components, per API-5L, as expressed below.
CE(IIW) = C +
Mn Cr + Mo + V Ni + Cu
+
+
≤ 0.43%
6
5
15
(note: IIW = International Institute of Welding)
- 46 Pipes are graded per their tensile properties. Grade X-65 means that SMYS (specified
minimum yield strength) of the pipe is 65 ksi. The yield strength is defined as the tensile
stress when 0.5% elongation occurs on the pipe, per API-5L [1]. The DNV code [2]
defines the yield stress as the stress at which the total strain is 0.5%, corresponding to
an elastic strain of approximately 0.2% and a plastic (or residual) strain of 0.3%, as
shown in Figure 7.1.1.
Figure 7.1.1 Yield Stress
Stress
SMYS
0.5 %
Strain
Strain
0.3%
Residual
strain
0.2%
Elastic
strain
In elastic region, when the load is removed, the pipe tends to go back to its origin. If the
load exceeds the elastic limit, the pipe does not go back to its origin when the load is
removed. Instead, the stress reduces the same rate (slope) as the elastic modulus and
reaches a certain strain at zero stress, called a residual strain.
- 47 Depending on pipe manufacturing process, there are several pipe types as:
•
Seamless pipe
•
DSAW (double submerged arc welding) pipe or UOE pipe
•
ERW (electric resistant welding) pipe
Seamless pipe is made by piercing the hot steel rod, without longitudinal welds. It is
most expensive but ideal for small diameter, deepwater, or dynamic applications.
Currently up to 24” OD pipe can be fabricated by manufacturers.
DSAW or UOE pipe is made by folding a steel panel with “U” press, “O” press, and
expansion (to obtain its final OD dimension). The longitudinal seam is welded by double
(inside and outside) submerged arc welding. DSAW pipe is produced in sizes from 18"
through 80" OD and wall thicknesses from 0.25" through 1.50".
ERW pipe is cheaper than seamless or DSAW pipe but it has not been widely adopted
by offshore industry, especially for sour or high pressure gas service, due to its variable
electrical contact and inadequate forging upset. However, development of high
frequency induction (HFI) welding enables to produce better quality ERW pipes. Figure
7.1.2 shows pipe types by manufacturing process.
- 48 -
Figure 7.1.2 Pipe Types by Manufacturing Process
(a) Seamless pipe
(b) UOE pipe
U-forming
(c) Continuous ERW pipe
O-forming
Expansion
- 49 -
7.2
CRA (Corrosion resistant alloy) Pipe
Depending on alloy contents, CRA pipe can be broken into follows:
• Stainless steel:
316L, 625 (Inconel), 825, 904L, etc.
• Chrome based alloy:
13 Cr, Duplex (22 Cr), Super Duplex (25 Cr), etc.
• Nickel based alloy :
36 Ni (Invar) for cryogenic application such as LNG
(liquefied natural gas) transportation (-160oC)
• Titanium:
Light weight (56% of steel), high strength (up to 200 ksi
tensile), high corrosion resistance, low elastic modulus,
and low thermal expansion, but high cost (~10 times of
steel). Good for high fatigue areas such as riser
touchdown region, stress joint, etc.
• Aluminum:
Light weight (1/3 of steel), low elastic modulus (1/3 of
steel), high corrosion resistance, but low strength (only up
to 90 ksi tensile). Applications can include casing, air can,
and risers.
Some key properties of each material are introduced in Table 7.2.1.
Table 7.2.1 Material Properties
Properties
Carbon Steel
Stainless Steel
Titanium
Aluminum
Specific Gravity
(Density)
7.85
8.03
4.50
2.70
(490 lb/ft3)
(500 lb/ft3)
(281 lb/ft3)
(168 lb/ft3)
Elastic Modulus
29,000 ksi
28,000 ksi
15,000 ksi
10,000 ksi
(@ 200oF)
(200,000 Mpa)
(193,000 Mpa)
(104,000 Mpa)
(69,000)
Thermal
Conductivity
30 Btu/hr-ft-oF
10 Btu/hr-ft-oF
(17 W/m-oC)
12 Btu/hr-ft-oF
(20 W/m-oC)
147 Btu/hr-ft-oF
(255 W/m-oC)
8.9 x 10-6 /oF
4.8 x 10-6 /oF
12.8 x 10-6 /oF
(16.0 x 10-6 /oC)
(8.6 x 10-6 /oC)
(23.1 x 10-6 /oC)
(51 W/m-oC)
(@ 125oC)
Thermal Expansion
6.5 x 10-6 /oF
Coefficient
(11.7 x 10-6 /oC)
1 ksi = 6.8948 Mpa
1 Btu/(hr-ft-oF) = 1.731 W/(m-oC)
- 50 Depending on sour contents in the fluid, different chrome based alloy pipe should be
selected as shown in Table 7.2.2.
Table 7.2.2 Chrome Based Alloy Pipe Selection for Sour Service
7.3
Conveyed Fluid
13% Cr
22% Cr
25% Cr
CO2
> 1%
> 1%
> 1%
H2S
< 0.04 bar
< 0.2 bar
< 0.4 bar
Cl
No
< 3%
< 5%
Clad Pipe
Clad pipe is a combination of low carbon steel (outer pipe) and CRA (inner pipe). This
pipe reduces material cost by using a thin wall CRA pipe at inner pipe wall surface to
resist internal corrosion. And the carbon steel outer pipe wall provides structural
integrity. Special caution should be addressed during clad pipe welding to the low
carbon steel pipe, since hydrogen induced cracking (HIC) can occur by dissimilar
material welding process.
7.4
Composite Pipe
A carbon-fiber or graphite material for small size pipe in low pressure application has
been developed for mostly topside piping and onshore pipeline. However, its application
is going to expand to subsea use due to its excellent corrosion resistant and low thermal
expansion.
7.5
Flexible Pipe
Flexible pipe consists of steel layers and plastic layers. Each layer is un-bonded and
moves freely from each other. It is known for excellent dynamic behavior due to its
flexibility. However, the flexible pipe size is limited by burst and collapse resistance
capacities. The maximum design temperature is 130oC due to the plastic layer’s limit.
The maximum pipe size made by industries is 19” (by year 2006). Flexible pipe’s
manufacturing limit (maximum design pressure) is shown in Figure 7.5.1.
- 51 -
Figure 7.5.1 Flexible Pipe Manufacturing Limit
Design Pressure (psi)
1400
1200
API 17J Design Limit
1000
800
600
Current Industry Limit
400
200
0
0
2
4
6
8
10
12
14
16
18
20
Pipe ID (inch)
Each steel and plastic layer has a different function as shown in Figure 7.5.2. For a sour
service, a stainless steel carcass is required. For a water injection line, a smooth plastic
bore can be used. The smooth bore is not normally used for gas applications due to gas
permeation problem. The pressure build-up in the annulus of the pipe can occur due to
diffusion of gas through the plastic sheaths. When no carcass is present, the inner
plastic layer will collapse if the annulus pressure exceeds the bore pressure, such as
shut-off case. To avoid this problem, gas vent valves are installed at end fitting to
relieve the annulus pressure. Rough bore (with carcass) can cause noise and vibrations
at high flow velocity.
The high density polyethylene (HDPE) is good for the content temperature of up to 65oC,
Rilsan/nylon for up to 90oC, and polyvinylidene fluoride (PVDF) for up to 130oC. PVDF
is better for higher temperatures but it is stiffer than nylon (3% vs. 7% in allowable
strain). Another key component of the flexible pipe is the end fitting (Figure 7.5.3) which
is designed to hold all layers of flexible pipe at each end.
The flexible pipe manufacturers include: Technip (formerly Coflexip), Wellstream, NKT,
and DeepFlex. To reduce the flexible pipe weight (especially for dynamic riser use) and
improve corrosion resistance, a composite material, such as for tensile wires, has been
developed. DeepFlex uses a composite material (carbon fibre-reinforced polymer
(CFRP)) for all layers (Figure 7.5.4.)
- 52 -
Figure 7.5.2 Flexible Pipe Structure [3]
External Sheath (HDPE)
- Protects abrasion, seawater
penetration, and steel layer corrosion
Intermediate Sheath (HDPE)
- Protects abrasion between steel layers
Pressure Layer
- Resists internal and external pressures
Pressure Sheath (HDPE/Nylon/PVDF)
- Contains internal fluid and transfers
internal pressure to pressure layer
Armour Wires - Resists tensile load
Carcass – Resists external
collapse pressure
Figure 7.5.3 Flexible Pipe End Fitting [4]
Figure 7.5.4 Composite Flexible Pipe [5]
- 53 -
7.6
Flexible Hose
Flexible hose is a single body rubber bonded (vulcanized, oven baked) structure, unlike
the flexible pipe which consists of unbonded multiple plastic and steel layers. The
flexible hose is commonly used for topside jumpers, single point mooring (SPM) risers,
and surface floating risers to offload the product from the buoy to FPSO or shuttle tanker
(see Figure 7.6.1)
Figure 7.6.1 Flexible Hose Applications
.
FPSO or
Shuttle Tanker
Offloading Hose
SPM Buoy
(mooring lines
not shown)
Risers
Pipeline
PLEM
Seabed
The built in one-piece end couplings with integral built in bend limiters and a composite
fire resistant layer provide a low minimum bend radius, a light compact construction with
excellent flexibility and fatigue resistance. However, there are some manufacturing
limits on hose size and length; the maximum hose size is 30” and the maximum length is
35 ft.
Flexible hose manufacturers include: Dunlop Oil & Maine, Bridgestone, GoodYear,
Phoenix Rubber Industrial (formerly Taurus), etc.
Figure 7.6.2 shows some pictures of flexible hose applications and factory flexibility test.
- 54 -
Figure 7.6.2 Pictures of Flexible Hose Applications and Factory Flexibility Test
(Source: www.dunlop-oil-marine.co.uk [6])
(Source: www.bridgestone.co.jp [7])
- 55 -
7.7
Coiled Tubing
Coiled tubing (CT) is a continuously milled tubular product reeled on a spool during
manufacturing process. Tubing diameter normally ranges from 0.75” to 6.625” and a
single reel can hold small size tubing lengths in excess of 30,000 ft. The world’s longest
continuously milled CT string is 32,800 ft. of 1.75” diameter. CT’s yield strengths range
from 55 ksi to 120 ksi [8].
CT has been developed for well service and workover and expanded the applications to
drilling and completion. To perform remedial work on a live well, three components are
required:
•
CT string: a continuous conduit capable of being inserted into the wellbore
•
Injector head: a means of running CT string into wellbore while under pressure
Stripper or pack-off: a device providing dynamic seal around the CT string
•
Some benefits of CT applications are: safe and efficient live well intervention, rapid
mobilization and rig-up resulting in less production downtime, and reduced
crew/personnel requirements, etc.
CT technology can be used for:
•
Well Unloading
•
Cleanouts
•
Acidizing/Stimulation
•
Velocity Strings
•
Fishing
•
Tool Conveyance
•
•
Well Logging (real-time & memory)
Setting/Retrieving Plugs
•
CT Drilling
•
Fracturing
•
Deeper Wells
Pipeline/Flowline, etc.
•
The coiled tubing manufacturers include Quality Tubing, Inc. (QTI) and Tenaris (formerly
Precision Tube Technology and Maverick Tube), etc.
Figure 7.7.1 shows a CT operation at onshore wellhead.
- 56 -
Figure 7.7.1 Coiled Tubing Operation [9]
CT String
Injector
Head
References
[1]
API 5L, Specification for Line Pipe, Section 6.2.1, American Petroleum Institute,
2004
[2]
DNV-OS-F101, Submarine Pipeline Systems, 2003, Sec. 5, C405
[3]
Technip USA Flexible Pipe Presentation
[4]
NKT Flexibles Website, www.NKTflexibles.com
[5]
DeepFlex Website, www.DeepFlex.com
[6]
Dunlop Oil Marine Website, www.dunlop-oil-marine.co.uk
[7]
Bridgestone Website, www.bridgestone.co.jp
[8]
“An Introduction to Coiled Tubing – History, Applications, and Benefits”,
International Coiled Tubing Association (ICTA), 2005
[9]
http://commservices.ssss.com/Literature/documents/
STEWARTANDSTEVENSONCTU.pdf
[10]
Farouk A. Kenawy and Wael F. Ellaithy, Case History in Coiled Tubing Pipeline,
OTC (Offshore Technology Conference) Paper No. 10714, 1999
[11]
Tim Crome, et. al., “Smoothbore Flexible Risers for Gas Export,” OTC Paper
#18703, 2007
- 57 -
8
PIPE COATINGS
8.1
Corrosion Coating
Inner surface of the pipe is not typically coated but if erosion or corrosion protection is
required, fusion bonded epoxy (FBE) coating or plastic liner is applied. Outer surface of
the carbon steel line pipes are typically coated with corrosion resistant FBE or neoprene
coating. The three layer polypropylene (3LPP), three layer polyethylene (3LPE, see
Figure 8.1.1), or multi-layer PP or PE is used for reeled pipes to provide abrasion
resistance during reeling and unreeling process. Thermally sprayed aluminum (TSA)
coating can be used for risers especially when there is a concern on CP shielding due to
strakes or fairings. abrasion resistant overlay (ARO) is commonly applied for the
horizontal directional drilling (HDD) pipes or bottom towed pipes.
The coating materials’ normal thickness and temperature limit are as follows:
–
–
–
–
Fusion Bounded Epoxy, 0.4-0.5 mm, 200oF
Polyethylene, 3-4 mm, 150oF
Polypropylene, 3-4 mm, 220oF
Neoprene, 3-5 mm, 220oF
Figure 8.1.1 3LPE Coating
Steel
FBE Layer
Adhesive Layer
HDPE Layer
- 58 -
8.2
Insulation Coating
To keep the conveyed fluid warm, the pipeline should be heated by active or passive
methods. The active heating methods include, electric heat tracing wires wrapped
around the pipeline, circulating hot water through the annulus of pipe-in-pipe, etc. The
passive heating method is insulation coating, burial, covering, etc.
Glass syntactic polyurethane (GSPU), PU foam, and syntactic foam commonly are the
commonly used subsea insulation materials (see Figure 8.2.1). Although these
insulation materials are covered (jacketed) with HDPE, they are compressed due to
hydrostatic head and migrated by water as time passes, so it is called a “wet insulation”.
Figure 8.2.1 GSPU (left) and Syntactic Foam Insulation (right)
OHTC or U value is used to represent the system’s insulation capability. Lower U value
prvides higher insulation performance. Heat loss can occur by three processes:
conduction, convention, and radiation. Conduction is a heat transfer through a solid by
contact, and convection is a heat transfer due to a moving fluid. Radiation is a heat
exchange between two surfaces (heat is radiated to the surrounding cooler surfaces).
Good insulation can be achieved by minimizing the above heat loss processes.
Conduction is dependent on material size and thermal conductivity. Convective heat
transfer (film) coefficient can be obtained from internal and external fluid Reynold’s and
Prandtl numbers.
- 59 The OHTC or U value can be obtained using the formula below:
U=
1
⎛ r ⎞ r 1
1 r1 ⎛ r2 ⎞ r1 ⎛ r3 ⎞
r
ln⎜⎜ ⎟⎟ + L + 1 ln⎜⎜ m ⎟⎟ + 1
+ ln⎜⎜ ⎟⎟ +
h1 K 1 ⎝ r1 ⎠ K 2 ⎝ r2 ⎠
K m−1 ⎝ rm−1 ⎠ rm hm
Where,
h1 = internal surface convective heat transfer coefficient
hm = external surface convective heat transfer coefficient
r = radius to each component surface
K = thermal conductivity of each component
rm
r1
For example, the U value for a 6.625” OD x 0.684” WT pipe with a 1” GSPU coating is:
r2 = 3.3125”
K1 = 30 Btu/hr-ft-oF
Pipe
r1 = 2.6285”
r3 = 4.3125”
K2 = 0.096 Btu/hr-ft-oF
GSPU
r2 = 3.3125”
Neglect FBE corrosion coating and HDPE outer jacket and assume h1 & h3 = 1,000
Btu/hr-ft2-oF.
U=
1
1
2.6285/12 ⎛ 3.3125 ⎞ 2.6285/12 ⎛ 4.3125 ⎞ 2.6285 1
ln⎜
ln⎜
+
⎟+
⎟+
1,000
30
0.096
⎝ 2.6285 ⎠
⎝ 3.3125 ⎠ 4.3125 1,000
= 1.65 Btu/(hr ⋅ ft 2 ⋅o F)
- 60 -
8.3
Pipe-in-Pipe
Another pipe insulation method is pipe-in-pipe (PIP) which an inner pipe is covered by a
larger outer pipe (Figure 8.3.1). The annuls between inner pipe and outer pipe are filled
with insulation materials including: micro-porous silica (Aerogel), polyurethane foam
(PUF), Wacker/Porextherm, Mineral wool, etc.
Figure 8.3.1 PIP
Aerogel
•
Microporous silica with a pore size of 10-9m.
•
Best U value 0.0139 W/m-oK at 50oC.
•
The density is 0.11 SG.
•
Developed for the reeling process and many track records exist.
•
Requires centralizers with a spacing of every 2m or so.
•
Cheaper than Wacker/Porextherm product.
PUF
•
2nd cheapest form of insulation.
•
2nd poorest U-value (0.029 W/m-oK at 50oC) of all insulation materials but used
extensively for S/J-lay projects, normally without centralizers.
•
Densities are in the range of 0.07 - 0.12 SG.
•
Use with reel-lay has been limited due to potential damage (compression and crack)
during reeling.
- 61 -
Wacker/Porextherm
•
Fumed microporous silica with a pore size of 10-6m.
Porextherm.
•
Most expensive thermal insulation product.
•
Good U-value (0.0195 W/m-oK at 50oC).
•
Standard density is 0.19 SG.
•
Developed for the reeling process and many track records exist.
•
Requires centralizers with a spacing of every 2m or so.
Wacker is purchased by
Mineral Wool
•
Cheapest form of insulation.
•
Poorest U-value (0.037 – 0.045 W/m-oK at 50oC) of all insulation materials but used
extensively in the North Sea.
•
Densities are in the range of 0.1 - 0.12 SG.
•
Not good for low U value unless combined with other method such as heat tracing.
PIP system requires bulkheads, water stops, and centralizers, depending on fabrication
methods. The end bulkhead is designed to connect the inner pipe to the outer pipe, at
each pipeline termination (see Figure 8.3.2). Intermediate bulkheads may require for
reeled PIP to allow top tension to be transferred between the outer pipe and the inner
pipe, at intervals of approximately 1 km. During installation, the tensioner holds the
outer pipe only, so the inner pipe tends to fall down by its dead weight and may result in
buckling at sag bend area near seabed, if no intermediate bulkheads exist.
Figure 8.3.2 End Bulkhead
Inner pipe
Outer pipe
Bulkhead
Flange
- 62 Water stops (see Figure 8.3.3) are installed to limit the pipeline length damaged in the
event that the annulus is flooded by pipeline failure or puncture. Considering low
fabrication cost and low heat loss, it is recommended to install one or two water stops
per each stalk length. The stalk length varies, due to spool base size and pulling
capacity, typically between 500 m to 1,500 m. It should be noted that the water stops
are not a design code requirement but they are recommended for deepwater project
where recovery of the flooded pipeline is challenging.
EPDM (ethylene propylene diene monomer) rubber, Viton (a brand of synthetic rubber),
and silicone rubber have been used for the water stop material. The axial compression
for the water stops is provided by using an interlocking clamp arrangement which will
provide the radial expansion of the ring against the pipe walls.
Centralizers or spacers (see Figure 8.3.3) are polymeric rings clamped on the inner pipe
for reeled PIP:
•
to protect insulation’s abrasion damage during insertion of the inner pipe into the
outer pipe
•
to protect insulation’s crushing due to bending load while reeling
•
to protect insulation’s crushing due to thermal bucking during operation
The centralizer works as a “heat sink” due to its high thermal conductivity (~0.3 W/m-oK ,
10 to 20 times higher than insulation materials). Therefore, reducing the number of
centralizers by increasing the centralizer spacing (2 m typical), or centralizer-less design
can reduce both the material and fabrication/installation costs.
Figure 8.3.3 Water Stop Seal (left) [1] and Centralizer (right) [2]
- 63 For the reeled PIP, the annulus gap needs to be sufficient to put insulation material,
centralizer, and clearance gap to account for the weld beads, welding misalignment,
pipe manufacturing tolerances, etc. The annulus gap should be in the range of 30 to 40
mm and the net gap (between insulation and outer pipe ID) should be 15 mm or higher
(see Figure 8.3.4). The maximum reeled PIP that has been installed by Technip is 12.2”
x 17” PIP for Dalia Project.
Figure 8.3.4 Reeled PIP with Centralizers
Inner Pipe
Annulus Gap
Outer Pipe
Net Gap
Insulation
Centralizer
- 64 -
8.4
Concrete Weight Coating
Concrete weight coating (Figure 8.4.1) is applied to make the pipe stable under the
water. One inch is the minimum concrete coating thickness that fabricator can put on. It
should be evaluated if concrete coating is the most cost effective option to increase pipe
weight. Increasing the pipe wall thickness may be more efficient considering pipe
transportation and project management cost for the concrete weight coating.
Figure 8.4.1 Concrete Weight Coating [3]
The polyethylene outer wrap in the above picture is removed after the concrete coating
is cured. Each pipe end is left without concrete coating for welding and welding
inspection. No coating is applied near the pipe end for automatic welding and automatic
ultrasonic test (AUT), as indicated in Figure 8.4.2. The concrete coating stop distance
from the pipe end is also called concrete cut-back length.
Figure 8.4.2 Coating Cut-Back Length
(Lengths shown below are for reference use only and can vary by contractor and project.)
Bare Steel
FBE
6”
15”
Concrete
- 65 -
8.5
Field Joint Coating
After the field weld is made, each pipe joint should be coated with a corrosion resistant
coating. The field joint coating (FJC) can be done by FBE, heat shrink sleeve, or PU
foam (for concrete coated pipe). Figure 8.5.1 presents one example of field joint coating
for insulation coated pipes.
Figure 8.5.1 Field Joint Coating [4]
- 66 References
[1] Dunlaw Engineering Ltd. website, http://www.dunlaw.com/bend_limiters.html
[2]
Oil & Gas Journal website,
http://www.ogj.com/display_article/112253/7/ARCHI/none/none/Innovations-keyreeled-pipe-in-pipe-flowline-for-gulf-deepwater-project/
[3]
Bayou Companies website, http://www.bayoucompanies.com
[4]
Pipeline Induction Heat website, http://www.pih.co.uk
[5]
M. Delafkaran and D.H. Demetriou, Design and Analysis of High Temperature,
Thermally Insulated, Pipe-in-Pipe Risers, OTC (Offshore Technology Conference)
paper No. 8543, 1997
- 67 -
9
PIPE WALL THICKNESS DESIGN
Pipe wall thickness (WT) should be checked for;
- internal pressure (burst)
- external pressure (collapse/buckle propagation)
- bending buckling
- combined load
Also the calculated pipe WT should be checked for thermal expansion, on-bottom
stability, free spanning, and installation stress.
9.1
Internal Pressure (Burst) Check
Pipe should carry the internal fluid safely without bursting. Design factor (inverse of
safety factor) used for burst pressure check (hoop stress) varies due to the pipe
application; oil or gas and pipeline or riser. The 0.72 design factor means a 72% of pipe
SMYS shall be used in pipe strength design. Riser is required to use a lower design
factor than the flowline/pipeline. This is because the riser is attached to a fixed or
floating structure and the riser’s failure may damage the structure and cost human lives,
unlike the pipeline failure. Moreover, gas riser uses lower design factor than the oil riser,
since gas is a compressed fluid so gas riser’s failure is more dangerous than the oil
riser’s.
Table 9.1.1 Design Factors [1] – [3]
System
Flowline
Design Factor
0.72
Code
30-CFR-250
0.60 (riser)
Pipeline (Oil)
0.72
0.60 (riser)
Pipeline (Gas)
0.72
0.50 (riser)
49-CFR-195
(ASME B31.4)
49-CFR-192
(ASME B31.8)
- 68 Using a conventional thin wall pipe formula, as used in ASME B31.4 and B31.8, the
required pipe wall thickness (t) can be obtained as;
t≥
Where,
P=
D=
S=
DF =
P×D
2 × S × DF
internal pressure (psi)
pipe OD (inch)
pipe SMYS (psi)
design factor
For example, for a gas pipeline with a 4,000 psi internal pressure (at water surface), the
required WT for a 16” OD and X-65 grade pipe is 0.684” as below.
t≥
4,000 × 16
= 0.684"
2 × 65,000 × 0.72
The empty pipe dry weight in air is 112.0 lb/ft and water displacement (buoyancy) is 89.4
lb/ft. Therefore, the pipe specific gravity is 1.25 (or 112.0/89.4). The submerged pipe
weight is 22.6 lb/ft (or 112.0-89.4 lb/ft).
The gas pipeline riser requires 0.985” WT pipe, using the same criteria as above but with
0.5 design factor.
t≥
4,000 × 16
= 0.985"
2 × 65,000 × 0.5
For a deepwater application, the external hydrostatic pressure should be accounted for
by using ∆P instead of P.
∆P = (internal pressure)max – (external pressure)min = Pi_max – Po_min
For the above example, the external pressure is zero at the platform, so there is no
change in WT calculation.
The above thin wall pipe formula assumes uniform hoop stress across the pipe wall and
gives a conservative result (high hoop stress). However, the hoop stress is not uniform
and it is maximum at inner surface and minimum at outer surface as shown in Figure
9.1.1. Therefore, a closed form solution of thick wall pipe (D/t<20) formula should be
used if more accurate hoop stress is required [6].
- 69 -
σh =
Where,
Pi a 2 − Po b 2 + a 2 b 2 (Pi − Po ) / r 2
b2 − a2
Thick wall pipe formula
a = inner pipe wall radius = Di / 2
b = outer pipe wall radius = Do / 2
r = arbitrary pipe radius (at which the hoop stress to be estimated)
By replacing r = a, the maximum hoop stress at inner pipe wall can be expressed as;
σh =
(Pi − Po ) D
(P − P ) t
− 0.5 (Pi +Po ) + i o
2t
2 (D − t)
Thick wall pipe formula @ inner wall
As a reference, the hoop stress formulas in another codes are listed below :
σh =
(Pi − Po ) D
− Pi
2t
API RP 2RD
σh =
(Pi − Po ) D
− 0.4 (Pi −Po )
2t
ASME B31.3 & Boiler Code
Figure 9.1.1 Pipe Hoop Stress Comparison
b
Po
a
Pi
σh_thick wall
σh_thick wall
σh_thin wall
c
t
Di
D
t
- 70 -
9.2 External Pressure (Collapse/Buckle Propagation) Check
The deepwater pipeline shall be checked for external hydrostatic pressure for its
collapse resistance and buckle propagation resistance. Normally the buckle propagation
resistance requires heavier WT than the collapse resistance. However, if a buckle
arrestor is installed at a certain interval (typically a distance equivalent to the water
depth), the buckle propagation is prevented or stopped (arrested) and no further damage
to the pipeline beyond the buckle arrestor can occur. In this way, we can save some
pipe material and installation cost by designing the pipe for collapse resistance.
The ASME code does not provide a formula to check for collapse resistance, thus the
API RP-1111 is normally used [7].
P −P
o
i
P =
c
max
≤f P
o c
P P
y e
P 2 +P 2
e
y
⎛t⎞
P = 2S⎜ ⎟
y
⎝D⎠
3
⎛t⎞
⎜ ⎟
⎝D⎠
= 2E
P
e
(1− ν 2 )
Where,
fo =
Pc =
Py =
Pe =
E=
M=
collapse factor, 0.7 for seamless or ERW pipe
collapse pressure of the pipe, psi
yield pressure collapse, psi
elastic collapse pressure of the pipe, psi
pipe elastic modulus, psi
possion’s ratio (0.3 for steel)
- 71 For example, for a 4,000 psi internal pressure gas pipeline in 3,000 ft water depth
(1,333.3 psi), the 16” OD x 0.684” WT, X-65 grade seamless pipe can resist collapse
pressure, as calculated below.
⎛ 0.684 ⎞
Py = 2 × 65,000 × ⎜
⎟ = 5,558 psi
⎝ 16 ⎠
3
⎛ 0.684 ⎞
⎜
⎟
16 ⎠
= 4,980 psi
Pe = 2 × 29,000,000 ⎝
(1 − 0.3 2 )
Pc =
5,558 × 4,980
5,558 2 + 4,980 2
= 3,724 psi
fo Pc = 0.7 × 3,724 = 2,607 psi
Po − Pi = 1,333.3 − 0 = 1,333.3 psi during installation (empty pipe)
Po − Pi = 1,333.3 − 4,000 = −2,666.7 psi during operation
Po − Pi
max
∴ Po − Pi
= 1,333.3 psi
max
≤ fo Pc ∴okay
Buckle propagation pressure (Pp) should be computed and checked with differential
pressure per API RP-1111 formula. If the buckle propagation pressure is higher than the
differential pressure, buckle will not propagate (travel). However, buckle will propagates
if the calculated buckle propagation pressure is less than the differential pressure.
⎡t ⎤
Pp = 24 S ⎢ ⎥
⎣D ⎦
2.4
If [Po − Pi ] max ≥ 0.8 Pp
then, buckle arrestor is required
- 72 As shown in the below calculations, the 16” OD x 0.684” WT, X-65 grade pipe requires
buckle arrestors in water depths greater than 1,453 ft (equivalent to 646 psi).
⎡ 0.684 ⎤
Pp = 24 × 65,000 ⎢
⎥
⎣ 16 ⎦
2.4
= 808 psi
0.8 Pp = 0.8 × 808 = 646 psi
[Po − Pi ] max = 1,333.3 psi
∴[Po − Pi ] max ≥ 0.8 Pp ∴ buckle arrestor is required
There are several types of buckle arrestors available; slip-on ring type and integral type
(Figure 9.2.1). Some contractors prefer thick wall pipe joint to buckle arrestor.
Figure 9.2.1 Buckle Arrestors
Steel
ring
(a) Slip-on Type
Epoxy
grouting
Forged ring
Welding
(b) Integral Type
- 73 -
9.3
Bending Buckling Check
Pipe WT should be checked for bending buckling during installation and operation per
API RP-1111.
(P − Pi ) ≤ g(δ)
ε
+ o
εb
Pc
ε = bending strain = 0.005 for installati on, 0.003 for operation
εb =
t
2D
g(δ ) = (1 + 20 δ) -1
δ=
D max − D min
= ovality
D max + D min
The same pipe as above with 1.0% ovality satisfies the bending buckling requirement as
calculated below.
εb =
t
0.684
=
= 0.0214
2 D 2 × 16
g(δ ) = (1 + 20 δ) -1 = (1 + 20 × 0.01) = 0.833
−1
ε (Po − Pi ) 0.005 1,333.3
+
=
+
= 0.381
εb
Pc
0.214
3,724
during installati on
ε (Po − Pi ) 0.003 − 2,666.7
+
=
+
= −0.702
εb
Pc
0.214
3,724
∴
ε (Po − Pi )
+
≤ g(δ )
εb
Pc
∴ okay
during operation
- 74 If the pipe is to be installed by a reel-lay method, the pipe WT needs to be checked for
buckling during reeling. For a reel drum radius of R, the required pipe WT for reeling is
estimated as:
t=
1.25 D 2
R
For a 31.5’ reel drum radius (Technip Deep Blue), the required pipe WT for the 16” OD
pipe is 0.847” as below:
t=
9.4
1.25 × 16 2
= 0.847"
31.5 × 12
Combined Load Check
The combined stress of hoop stress (Sh) and longitudinal (axial compression or tension)
stress (SL) should not exceed 90% of the pipe SMYS during operation, per ASME B31.8.
There is no maximum combined stress limit for hydrotesting in this code, but it is allowed
by industry to use 100% SMYS during hydrotest.
Table 9.4.1 Design Factors (ASME B31.8)
Hoop Stress, F1
Longitudinal Stress, F2
0.72 (pipeline)
0.80
Combined Stress, F3
0.90 (operation)
0.50 (riser)
1.00 (hydrotest)
The combined stress can be calculated using Von Mises formula as below, neglecting
torsional (tangential) stress:
Von Mises Stress =
S h − SL S h + SL ≤ F3 (SMYS )
2
2
The longitudinal stress comes from tension and bending loads due to installation, route
curvature, free span, thermal expansion, etc. As shown in Figure 9.4.1, the maximum
allowable Von Mises Stress curve gives less conservative results than the Tresca stress
curve. If the calculated Von Mises stress falls inside of the curve, the pipe is considered
safe in terms of combined resultant stress.
- 75 It should be noted that, for the same tensional and compressive stress at a positive hoop
stress, the pipe may not be safe for the compression (see point B in Figure 9.4.1).
Figure 9.4.1 Von Mises Stress Curve [6]
σh
B (unsafe)
A (safe)
σL
(Tresca Stress)
Von Mises Stress
σL
σh
- 76 References
[1]
49 CFR, Part 192, Transportation of Natural and Other Gas by Pipeline:
Minimum Federal Safety Standards
[2]
49 CFR, Part 195, Transportation of Hazardous Liquids by Pipeline
[3]
30 CFR, Part 250, Oil and Gas and Sulfur Operations in the Outer Continental
Shelf
[4]
ASME B31.4, Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum
Gas, Anhydrous Ammonia and Alcohols, 1999
[5]
ASME B31.8, Gas Transmission and Distribution Piping Systems, 1999
[6]
Advanced Mechanics of Materials, Arthur P. Boresi, Richard J. Schmidt, and
Omar M. Sidebottom
[7]
API RP-1111, Recommended Practice for Design Construction, Operation, and
Maintenance of Offshore Hydrocarbon Pipelines, 1999
[8]
API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and
Tension-Leg Platforms (TLPs), First Edition, 1998
[9]
ASME B31.3, Chemical Plant and Petroleum Refinery Piping
[10]
DNV-OS-F101, Submarine Pipeline Systems, 2003
[11]
Alexander Blake, “Practical Stress Analysis in Engineeering Design,” Marcel
Dekker, Inc., 1990
[12]
Joseph E. Shinley and Larry D. Mitchell, “Mechanical Engineering Design,”
McGraw-Hill Book Company, 1983
[13]
C.P. Sparks, “The Influence of Tension, Pressure and Weight on Pipe and Riser
Deformations and Stresses,” Journal of Energy Resources Technology,
Transactions of the ASME, March 1984
[14]
Jaeyoung Lee and Don Herring, "Improved Pipe Hoop Stress Formula,"
Deepwater Pipeline & Riser Technology Conference, Houston, Texas, 2000
[15]
Jaeyoung Lee, "Modified Thin Wall Pipe Formula for Deep Water Application,"
International Society of Offshore and Polar Engineering (ISOPE) Conference,
Canada, 1998
- 77 -
10
THERMAL EXPANSION DESIGN
Thermal expansion is an important issue in deepwater flowlines design since flowlines
normally carry very high pressure and temperature fluid, unlike export pipelines. The
thermal elongation is a function of the pipe material’s thermal expansion coefficient (α),
differential temperature (δT) between the conveyed fluid temperature and the ambient
temperature when the pipe is welded, and the pipeline length (L). If a 1.0 miles of
carbon steel pipe (α = 6.5 x 10-6 /oF) is operated at 100oF differential temperature, the
pipeline end elongation (δL) will be:
(
)
δL = α (δT ) L = 6.5 × 10 -6 × 100 × 5280 = 3.4 ft
However, the pipe/soil friction force resists the pipeline expansion, so the above
estimated pipeline end elongation will be reduced significantly. The thermal expansion
analysis is not simple and FEA (finite element analysis) tools are commonly used to
handle sea bottom irregularities, flowline route curvatures, and pressure and
temperature variance along the route. Snaking (lateral displacement) or upheaval
buckling (vertical displacement) can occur due to excessive flowline enlogation when
both ends are restrained and are not allowed to move freely.
Figure 10.1 Snaking and Upheaval Buckling
(a) Snaking
(a) Upheaval Buckling
(Source: www.jee.co.uk)
- 78 To control or mitigate the thermal expansion problems, such methods can be adopted as
follows (also see Figure 10.2):
•
Snake lay
•
Expansion loop
•
Flexible jumper
•
Inverted “U” or “M” shape rigid jumper
•
Sliding PLET
•
Random buckle initiators (sleepers, buoyancies, etc.)
•
Random buckle arrestors (random rock dumping, burial, anchor, etc.)
Figure 10.2 Thermal Expansion Mitigation Methods
(a) Sliding PLET
(b) A Sleeper under the Flowline
- 79 -
Figure 10.2 Thermal Expansion Mitigation Methods (continued)
L
Plan View - without Buoyancy
(Shorter Wave Length – Smaller Curvature Radius – Higher Stress)
Distributed Buoyancy
L
Plan View – with Distributed Buoyancy
(Longer Wave Length – Less Curvature- Lower Stress)
(c) Distributed Buoyancies
Flowline tends to expand (elongate) to each end of the flowline while the soil holds the
axial movement of the flowline. At a certain point, the soil friction resistance equals or
exceeds the flowline expansion load. Beyond this point, called a virtual anchor point, the
flowline will not move. The flowline walking can occur when the virtual anchor point
moves between when flowline is warmed (operation) and when it is cooled down (see
Figure 10.3). Repeated shutdowns and startups cycles may cause the axial walking and
require anchor pile to hold back the flowline from walk-away. Otherwise, a steel
catenary riser (SCR) may buckle due to reduced sag bend radius at seabed due to
accumulated pipeline walking.
- 80 -
Figure 10.3 Flowline Walking Phenomenon
Moved virtual
anchor point
Tension
Diagram
Shutdown
Flowline
distance
Operation
Compression
Riser end
Flowline/Riser
Profile
< Walking occurs >
Before
After
Flowline end
- 81 References
[1]
Jee web site, www.jee.co.uk
[2]
Han S. Choi, Expansion Analysis of Offshore Pipelines Close to Restraints,
ISOPE (International Society of Offshore and Polar Engineering) Conference,
1995
[3]
C. J. M. Putot, Localized Buckling of Buried Flexible Pipelines, OTC (Offshore
Technology Conference) Paper No. 6155, 1989
[4]
I. R. Colquhoun, et.al., Maximum Allowable Temperature Differentials in Buried
Pipelines, OMAE (Offshore Mechanics and Arctic Engineers) Conference, 1992
[5]
I. G. Craig, et. al., Upheaval Buckling : A Practical Solution Using Hot Water
Flusing Technique, OTC (Offshore Technology Conference) Paper No. 6334,
1990
[6]
A. C. Palmer, et. al., Design of Submarine Pipelines Against Upheaval Buckling,
OTC (Offshore Technology Conference) Paper No. 6335, 1990
[7]
M. Finch, Upheaval Buckling and Floatation of Rigid Pipelines: The Influence of
Recent Geotechnical Research on the Current State of the Art, OTC (Offshore
Technology Conference) Paper No. 10713, 1999
[8]
R. Bruschi, et. al., Lateral Snaking of Hot Pressurized Pipelines Mitigation for
Troll Oil Pipeline, 1996 OMAE, 1996
[9]
James G. A. Croll, A Simplified Analysis of Imperfect Thermally Buckled Subsea
Pipelines, International Journal of Offshore and Polar Engineering, Vol. 8, No. 4,
1998
[10]
R.R. Hobbs and F. Liang, “Thernal Buckling of Pipelines Close to Restraints,”
International Conference on OMAE (Offshore Mechanics and Arctic Engineering)
1989
[11]
Jie Zheng, Xinhai Qi, and Mark Brunner, “Effects of Soil Resistance on Lateral
Buckling of Pipelines,” DOT (Deep Offshore Technology) 2002
[12]
Mark Brunner, Xinhai Qi, and Jun Chao, “Challenges and Solutions for
Deepwater HP/HT Flowlines,” DOT (Deep Offshore Technology) 2003
- 82 -
- 83 -
11
PIPELINE ON-BOTTOM STABILITY DESIGN
Pipeline laid on the sea floor should be stable during installation, after installation, and
during operation. If the pipe is too light during installation, it will be hard to control the
pipe since it behaves like a noodle due to waves & current and installation vessel’s
motion. Most installation contractors require a minimum 1.15 pipe SG (specific gravity)
to avoid pipe buckling which may occur due to pipe’s excessive movement during
installation.
After installation, before the pipe is filled with water or product fluid, the pipe should be
checked for 1 year return period waves and current conditions. If the pipe is laid as
empty for a long period before commissioning, a 2-year, 5-year, or 10-year return period
metocean data should be used. During operation, the pipe should be stable for a 100year return period metocean data.
The soil data is very important to estimate the pipeline on-bottom stability. If no soil data
is available, use the following data for the pipe-soil lateral friction coefficients per DnVRP-F109, On Bottom Stability of Offshore Pipeline Systems:
• Clay
0.2
• Sand
0.6
• Gravel
0.8
To keep the pipeline stable, the soil resistance should be greater than the hydrodynamic
force induced on the pipeline.
µ (W s − FL ) ≥ (FD + FI )
Eq. 11.1
Where,
FL =
1
ρ w D CL V 2
2
FD =
1
ρ w D C D V V Drag Force
2
FI =
π D2
ρ w CM A
4
Lift Force
Hydrodynamic
Force
Inertia Force
Soil Resistance
- 84 µ is the soil friction coefficient as mentioned in the previous paragraph; WS is the pipe
submerged weight (lb/ft); ρw is the water mass density (64 lb/ft3); V is the near-bottom wave
& current velocity; and A is the water particle acceleration corresponding to the V. The
recommended lift, drag, and inertia force coefficient (CL, CD, and CM) is 0.9, 0.7, and 3.29
respectively.
The AGA pipeline on-bottom stability program [1] is widely used by industries. The
program has three modules:
•
Level 1 – Simple and quick static analysis using a linear wave theory and Morison
equations as above, without accounting for pipe movement or selfembedment.
•
Level 2 -
Reliable quasi-static analysis using a non-linear wave theory and
numerous model test results considering pipe’s self-embedment.
•
Level 3 -
Complicated dynamic time domain analysis using series of linear waves
and allowing some pipeline movements. Compare the computed pipe
stresses and deflections with allowable limits.
Level 2 is recommended for most cases. Level 3 can be used to predict pipeline
movements especially for dense sand or stiff clay where the pipe embedment does not
take a big role. However, Level 3 takes a long computer running time and it is difficult to
estimate how far the pipeline will move over the design life. Therefore, Level 3 is not
recommended unless small savings of concrete coating can affect the project cost
significantly.
In Level 2 analysis, it is noted that the vertical safety factor in the output should be
treated as a reference use only. This is because the lift force is already considered in
the horizontal stability check (see Eq. 11.1) and the lift force is calculated based on the
pipe sitting on the seabed. Once the pipe is lifted off the seabed, the water will start to
flow underneath the pipe. The underneath flow velocity is faster than the upper flow,
thus the underneath pressure is less than the upper pressure. This pressure differential
tends to push the pipeline back to the seabed and drastically reduces the lift force.
- 85 The following methods (also see Figure 11.1) can be adopted to keep the pipeline stable
on the sea floor:
•
•
•
•
•
•
•
Heavy (thick) wall pipe
Concrete weight coating
Trenching
Burial
Rock dumping (covering)
Concrete mattress or bitumen blanket
Concrete block
Figure 11.1 Some of Pipeline On-bottom Stability Mitigation Methods
Trenching
Rock Dumping
Concrete Mattress
Concrete Block
- 86 References
[1]
Submarine Pipeline On-bottom Stability Analysis and Design Guidelines,
American Gas Association, 1993
[2]
C.P. Ellinas, et. al., Prevention of Upheaval Buckling of Hot Submarine Pipelines
by Means of Intermittent Rock Dumping, OTC (Offshore Technology Conference)
Paper No. 6332, 1990
[3]
Submar Website, www.submar.com, for concrete mattress
[4]
Van Oord Website, www.vanoord.com, for rock dumping
[5]
Jaeyoung Lee and Keh-Han Wang, "Stability of Pipeline under Oblique Waves,"
Oceans 2001, Honolulu, Hawaii, 2001
[6]
Guideline for the Design of Buried Steel Pipe, ASCE, 2001,
http://www.americanlifelinesalliance.org/pdf/buried_pipe.pdf
[7]
Guidelines for the Seismic Design of Oil and Gas Pipeline Systems, ASCE, 1984
[8]
SeaMark Systems, http://www.seamarksystems.com, for concrete/bitumen
mattress
[9]
Pipeshield International Ltd., http://www.pipeshield.co.uk, for concrete block and
mattress
[10]
Pro-Dive Marine Services, http://www.prodive.ca, for mattress and fabric
formwork
[11]
SLP Engineering, http://www.slp-eng.com/Submat/Grout-Bags.asp, for grout bag
and bitumen mattress
- 87 -
12
PIPELINE FREE SPAN ANALYSIS
Pipeline free spans could exist at irregular seabed terrain or fault areas. The best way is
to avoid free spans but if not avoidable, it is necessary to check if the anticipated free
span length is acceptable for static and dynamic loads. The static loads include dead
weight of the pipe and waves & current induced hydrodynamic load. Figure 12.1 shows
one example of static pipe stress near free span areas. The dynamic loads come from
vortex induced vibration (VIV, see Figure 12.2) and fatigue damage.
Figure 12.1 Static Free Span Stress
Figure 12.2 Dynamic VIV Loads
Cross-flow vibration
Inline-flow vibration
Wave &
current
Wave &
current
(small amplitude)
(large amplitude)
- 88 The DnV-RP-F105 (Free Span Pipelines, 2006) and DnV’s FatFree Program can be
used to check for the maximum allowable free span length. If the actual free span length
exceeds the maximum allowable free span length, the free span should be corrected
using one of the mitigation methods below (also see Figure 12.3):
•
Alteration of seabed (cut-off high seabed spots by plough or trencher)
•
Concrete mattress or sand-cement bags
•
Mechanical support
•
Strakes or fairings
Figure 12.3 Examples of Free Span Mitigation Methods
(a) Mechanical support
(b) Strakes
(c) Fairings
- 89 References
[1]
Submarine Pipeline On-bottom Stability Analysis and Design Guidelines,
American Gas Association, 1993
[2]
B.M. Sumer and J. Fredsoe, A Review on Vibrations of Marine Pipelines, ISOPE
(International Society of Offshore and Polar Engineers) Conference, 1994
[3]
L.Lee and D.W. Allen, “The Dynamic Stability of Short Fairings,” OTC Paper
#17125, 2005
[4]
CRP Website, www.crpgroup.com/cable_protection.htm
[5]
Mark Tool & Rubber Co. Inc. Website, www.marktool.com
- 90 -
13
CATHODIC PROTECTION DESIGN
Corrosion is a deterioration of a material due to reaction with its environment (oxidation
or chemical reaction). It is a natural tendency of a refined material (steel) to return to its
original state (iron ore). A corrosion resistance coating is applied to prevent corrosion,
but a cathodic protection (CP) system using anodes is used as a supplemental corrosion
protection system. This is because the corrosion coating can be damaged during pipe
transportation and installation.
For the pipeline CP system, half shell anodes are tied-on the pipe outer surface at
certain intervals. Typically 75 to 115 lb aluminum alloy anodes are installed at 200 to
1,000 ft intervals. Structural anodes can also be installed at PLET, to reduce offshore
anode installation time and to keep the anode from being buried into the soil. For the
case of installing the anodes on the PLET, attenuation calculation is needed to check if
the anode current can flow to the designated distance.
Design guidelines can be found at DNV-RP-F103 (Cathodic Protection of Submarine
Pipelines by Galvanic Anodes, 2006), DNV-RP-B401 (Cathodic Protection Design,
2005), and ISO-15589-2 (Petroleum and Natural Gas Industries – Cathodic Protection of
Pipeline Transportation Systems – Part 2: Offshore Pipelines, 2004) (Ref. [1] - [3]).
There are four components in CP system (see Figure 13.1) as follows:
(1) Anode (lower electrical potential) – the point that corrosion occurs (oxidation or
production of electrons)
(2) Cathod (higher electrical potential) – the point that consumption of electrons occurs
(3) Electrolyte – electrically conductive fluid (water or air)
(4) Return Circuit (metallic path) – electrons move from anode to cathode
Figure 13.1 CP System Components
Anode (-)
e
Cathod (+)
Current
- 91 Galvanic or sacrificial anodes are made of zinc, magnesium, and aluminum. The
electrochemical potential, current capacity, and consumption rate of these alloys are
superior for CP than iron. The driving force for CP current flow is the difference in
electrochemical potential between anode and cathode. Table 13.1 shows some
materials’ electrochemical potentials.
Table 13.1 Electrochemical Potential - Galvanic Series
Materials
Electrochemical Potential (-V)
Pure magnesium
1.75
Magnesium alloy
1.6
Zinc
1.1
Aluminum alloy (5% zinc)
1.05
Pure aluminum
0.8
Mild steel
0.5 to 0.8
Mild steel (rusted)
0.2 to 0.5
Cast iron
0.5
Mild steel in concrete
0.2
Copper, brass, bronze
0.2
Å Anode
Å Cathod
Anodes types to be used for pipeline CP system are shown in Figure 13.2 below. A
concrete mattress with integrated anodes embedded in concrete blocks has been
developed to provide both pipeline stabilization and a local CP source.
- 92 -
Figure 13.2 Anode Types for Pipeline CP System
Square End Bracelet
(for concrete coated pipe)
Tapered End Bracelet
(for non-concrete coated pipe)
Structural Anode
(for PLET)
CP Mattress
(Source: www.stoprust.com [4])
- 93 -
Table 13.2 Tapered Bracelet Anode Dimensions [5]
Please refer to www.galvotec.com for non-tapered bracelets for concrete coated pipes.
- 94 References
[1]
DNV-RP-F103, Cathodic Protection of Submarine Pipelines by Galvanic Anodes,
2006
[2]
DNV-RP-B401, Cathodic Protection Design, 2005
[3]
ISO-15589-2, Petroleum and Natural Gas Industries – Cathodic Protection of
Pipeline Transportation Systems – Part 2: Offshore Pipelines, 2004
[4]
CP-Mat Catalogue, by Deepwater Corrosion Services, Inc (www.stoprust.com)
and Submar, Inc. (www.submar.com)
[5]
Galvotec website, www.galvotec.com
- 95 -
14
PIPELINE INSTALLATION
14.1
Pipeline Installation Methods
In early days, the pipeline was fabricated at beach and towed to the project field by a tug
boat. Most widely used installation method is using a pipeline installation vessel which
can weld pipe joints on the deck and lower the pipes by releasing the pipes from the
tensioners while moving the vessel. Depending on the pipeline’s profile from the vessel
to the sea floor, it is called S-lay or J-lay. Another installation method is to fabricate the
pipeline at spool base near beach and reel the pipe onto the reel ship. Then the reel
ship carry the reeled pipe to the project field and lay by un-spooling the pipes.
The four (4) pipeline installation methods are listed below and illustrated in Figure
14.1.1.
•
Towing – bottom tow, near bottom tow, mid-depth tow, and surface tow
•
S-Lay
•
J-Lay
•
Reel-Lay
Figure 14.1.1 Pipeline Installation Methods
- 96 In shallow waters, an anchor moored barge cab be used but a dynamic position (DP)
vessel is widely used for deepwater installation. Details of each installation method are
listed below.
(1) Towing
•
•
•
•
Made up of a carrier pipe (up to 60” to date) with several components (bundle) inside
near beach
Limitations on length that can be fabricated (beach size limit) and installed (towing
limit)
Carrier pipe provides a corrosion free environment internally
Requires several support vessels (cheaper ones than S/J/Reel-lays)
(2) S-Lay
•
•
•
•
•
Pipeline is fabricated on the vessel using single, double, or triple joints
Requires a “stinger” up to 100m long, either single section or two/three articulated
sections
Deeper water requires longer stinger and higher tension resulting in more risk
Typical lay rate is approximately 3.5km per day
Maximum installable pipe size is 60”OD by AllSeas Solitaire
(3) J-Lay
•
•
•
•
•
•
Welding is done on vessel, but at one station, so is slower
Pipe has a departure angle very close to vertical, so less tension is required
Principal application is for deep water
Stinger is not required
Typical lay rate is approximately 1 - 1.5 km per day
Maximum installable pipe size is 32”OD by Saipem S-7000
(4) Reel-Lay
•
•
•
•
•
Pipe welded onshore in a controlled environment and spooled onto vessel in
continuous length until complete or maximum capacity is reached
Much lower tension and therefore more control than S lay
Limited on coating types – no concrete coating or stiff insulation coating
Limitations on reeling capacity by volume or weight
Typical lay rate is 14 km per day
- 97 Typical S-lay tensioner and stinger are shown in Figure 14.1.2. S-lay and J-lay
configuration is shown in Figure 14.1.3 and Figure 14.1.4 respectively. There are
multiple welding stations in S-lay, depending on pipe size and pipe WT. Therefore, it is
important to control the time spending at each station. If one station spends 10 minutes
while the others spend 5 minutes, the pipe lay rate is reduced by 50%. For example, if
each station takes 7 minutes to connect one pipe joint (40 ft), the lay rate would be 1.6
miles per day as below:
(24 x 60 min/day) / (7 min/40 ft) = 8,230 ft/day = 1.6 miles/day
The J-lay has only one welding station but can weld multiple pipe joints such as triple to
hex joints (120 ft to 240 ft).
Pipe strain or curvature variance during reel-lay is presented in Figure 14.1.5. The pipe
strain is near zero when the pipe departs the stinger. The pipe is reeled on a spool at
spooling base as shown in Figure 14.1.6. The maximum reelable pipe size is 18” OD
due to pipe strain and tension limit during reeling. The combined strain during reeling
process will reach approximately 3% to 4% (note: yield is 0.5% and ultimate tensile is
5%). The reeled pipe WT needs to be thick enough to avoid wrinkle (see Section 9.3).
Figure 14.1.2 S-Lay Tensioner and Stinger
Stinger
Tensioner [1]
- 98 -
Figure 14.1.3 S-Lay Configuration
Welding Station #3
Welding
Inspection
Station
Plan
Tensioner
Welding Station #2
Welding Station #1
Installation Vessel
Stinger
40-ft or 80-ft Pipe Joints
Tensioner
Profile
Rollers
Stinger
Figure 14.1.4 J-Lay Configuration
Traveling tensioner
J-lay tower
Fixed tensioner
Triple or quadruple joints (120-ft or
160-ft) with a collar installed in the
middle of the last joint
Welding/inspection station
Installation Vessel
Rollers
- 99 -
Figure 14.1.5 Pipe Moment-Curvature Changes during Reel-Lay
3
2
1
4
moment
5
1
3
5
curvature
4
2
Figure 14.1.6 Spooling Base
- 100 -
14.2
Pipeline Installation Vessels
There are many offshore pipeline installation vessels available worldwide [2]. Some
deepwater installation vessels are shown in Figure 14.2.1.
As a reference, some dynamically positioned (DP) vessels which can lay pipes in water
depth greater than 3,600 ft are listed in Table 14.2.1. Table 14.2.2 presents several
reel-lay vessels’ reeling capabilities.
Figure 14.2.1 Deepwater Pipeline Installation Vessels
Allseas, Lorelay
(S-Lay)
Subsea 7, Skandi Navica
(Reel-lay)
- 101 -
Table 14.2.1 Deepwater Pipeline Installation Vessels
Tension
capacity
Max. pipe OD
(kips)
(inch)
Max.
water
depth*
(ft)
Lorelay
360
30
10000+
S
Solitaire
1200
60 (S) / 18 (Reel)
10000+
S
Audacia
1155
44
10000+
S (2007)
Intrepid
268
12
8000
S / Reel
Express
352
14
?
J / Reel
Caesar
891
36
6560
S/J
Hercules
1200
60 (S) / 18 (Reel)
8000+
S / Reel
Chickasaw
180
12
6000
S/Reel
Heerema
Balder
1250
32
10000
J
J. Ray
McDermott
DB50
20
10000
J / Reel
48 (S/J)/10 (Reel)
10000
S / J / Reel
1160
32
10000
J
881 (J)
551 (Reel)
20
10000
J / Reel
Falcon
300
14
9840
J
Kestrel
265
12
5000
J / Reel
Polaris
529
60 (S/J)/18 (Reel)
7000
S / J / Reel
Sapura
3000
528
60
6560
S / J (2007)
Deep Blue
1697
28 (J)/18 (Reel)
10000
J / Reel
Apache
440
16
5000
Reel
Constructor
440
14
5000
J / Reel
160
12
10000
S / J / Reel
500
19
9500+
Reel
Fennica
500
19
6500
Reel
Seven
Oceans
880
16
?
Reel
Contractor
Allseas
Helix
(Cal Dive)
Global
Vessel
DB16
Saipem
S-7000
FDS
Acergy
(Stolt)
Technip
Torch
Subsea 7
Midnight
Express
Skandi
Navica
775 (J)
100 (Reel)
300 (S/J)
100 (Reel)
Lay
method
* Maximum water depth for small pipe sizes. The installable water depth varies with pipe size
and weight.
- 102 -
Table 14.2.2 Reeling Capacity
Contractor
Cal Dive
Global
Vessel Name
Intrepid
Hercules
Reel flange diameter (ft)
?
116
Reel hub diameter (ft)
?
Reel width between flanges (ft)
Pipe weight capacity (short ton)
Number of reels (ea)
Subsea
7
Skandi
Navica
Technip
Technip
Deep
Blue
Apache
82
101.7
82
59
54
64
54
?
23.5
22
17.06
21.3
1700
6500
2750
3080
2200
1
1
1
2
1
- 103 -
14.3
Pipeline Installation Analysis
Pipe structural integrity should be checked for during installation operation, including
initiation, normal lay, and termination. Also, abandonment & recovery (A&R), single
point lift (SPL), and davit lift analysis should be performed for contingency occasions.
To determine whether the designed pipe can be installed by any installation vessel
currently available in the industry, at least the normal installation analysis should be
done before the pipe ordered. The installation vessel’s limit such as tensioner, stinger,
etc. should be checked in pipeline installability evaluation. Several programs available
for pipeline installation analysis are: Offpipe, Orcaflex, Flexcom, etc.
The pipe stress limit during installation is not specified in any industry codes or
standards. However, industry uses 72% SMYS at sagbend and 85% SMYS at
overbend. At sagbend, the pipe is hard to control, like at stinger, so more stringent
stress limit (lower stress limit) is applied. For the dynamic analysis, higher stress limits
are used since more severe environment and vessel motion are considered. If strain
criteria are used, a 0.15% and 0.20% strain can be used at sagbend and overbend,
respectively. Figure 14.3.1 shows one example of pipe stress analysis results.
•
Overbend:
85%SMYS (static)
100%SMYS (dynamic)
•
Sagbend:
72%SMYS (static)
96%SMYS (dynamic)
Figure 14.3.1 Example of Pipe Stress Analysis Results
- 104 Figure 14.3.2 illustrates A&R procedures. For abandonment, the A&R cable from a
winch on the vessel is attached to the pipe pull- head. While moving the vessel, the
A&R cable is lowered to the sea floor. Recovery follows the reversed order of the
abandonment procedures.
Single point lift (SPL) is similar to the A&R operation except no-use of stinger. The SPL
cable from a crane or davit on the vessel is free hanged vertically, at side of the vessel.
Multiple davits can be used to minimize the pipe stress during lifting and lowering the
pipeline, as shown in Figure 14.3.3.
Figure 14.3.2 Abandonment and Recovery Sequence
A&R cable
Pipeline
Recovery
Abandonment
- 105 -
Figure 14.3.2 Davit Lift
Davits
Davit cables
Pipeline
- 106 References
[1]
Dominique Perinet and Ian Frazer, “J-Lay and Steep S-Lay: Complementary Tools
for Ultradeep Water,” OTC 18669, 2007
[2]
Offshore magazine poster, or
www.pennwellpetroleumgroup.com/resourcecenter/os_poster_series.cfm
[3]
Tim Crome, “Reeling of Pipelines with Thick Insulation Coating, Finite-Element
Analysis of Local Buckling,” OTC (Offshore Technology Conference) Paper No.
10715, 1999
[4]
Ruxin Song and Paul Stanton, “Deepwater Tie-back SCR: Unique Design
Challenges and Solutions,” OTC 18524, 2007
[5]
E.P. Heerema, “Recent Achievement and Present Trends in Deepwater Pipe-lay
Systems,” OTC Paper #17627, 2005
[6]
Brett Champagne, Derek Smith, et al., “The BP Bombax Pipeline Project – Design
for Construction,” OTC Paper #15271, 2003
- 107 -
15
SUBSEA TIE-IN METHODS
Unlike onshore tie-ins, it is difficult to make subsea tie-ins in terms of material handling,
pipe cutting, welding, etc. Subsea tie-in is typically made by diver-assisted flange
connectors for shallow water pipelines and diverless remotely operated vehicle (ROV)
connectors for deepwater pipelines.
There are three types of connectors available: flange, clamp (Graylok type), and collet
connectors. Clamp or collet connector is more favorable over the flange connector due
to ROV operability, offshore connection time, and available tie-in tools from contractors.
Flange connector is industry proven technology and can be easily procured from
vendors’ shelf. However, due to lengthy subsea connection time, unfriendly ROV
operation, and limited availability of connection tools/systems, the flange connector is
not recommended for deepwater application.
Clamp connector is compact and widely used for deepwater tie-ins. A single bolt with
hinge system clamp connector is preferable for the diverless ROV connection. The seal
ring between two hubs provides very secure mechanical sealing as the internal pressure
is energized.
Collet connector is more expensive and complicated than any other connectors.
Hydraulic pressure is used to close the fingers of collets and set the drive ring which
locks the collets. There are two types of collet connectors; integral and non-integral. An
integral collet connector has a self-contained actuator and is much larger and more
expensive than a non-integral collet connector. A non-integral collet connector requires
an external, reusable actuator that is deployed and retrieved by a running tool. Nonintegral collet connector is more compact than integral collet connector and economical
when more than three collet connectors are required (if only one running tool is
required).
Figures 15.1 and 15.2 show each connector components and collet connector assembly
sequence, respectively. Table 15.1 shows each connector type’s advantages,
disadvantages, and available vendors.
- 108 -
Figure 15.1 Connector Types
Compact Flange (top) and ANSI Flange (bottom)
Flange Components
Clamp
Hub
Four Bolts Clamp Connector
Seal Ring
Clamp Connector Components
Single Bolt Clamp Connector
Collet Connector Components
- 109 -
Figure 15.2 Collet Connector Assembly Sequence
- 110 -
Table 15.1 Pros and Cons of Each Connector
Flange
Clamp
Collet
- Industry proven
- Industry proven
- Industry proven
- Least expensive connector
- Diverless single or dual
bolting system
- No bolt required
- Least procurement time
(standard components)
- Long installation time (16-20
hrs for 12-inch connector)
- Quick connection time
- Lighter than other
connectors
- OSI RAC (Remote
Articulated Connector) can
accommodate some
misalignment (~5o)
- Quick connection time
- Accommodate some
misalignment (+2o)
- Most expensive and
complicated connector
- More expensive than flange
- Conventional ANSI Flange:
Numerous vendors
Oceaneering (Grayloc)
Oil States Industries (OSI)
Vetco Gray (GSR)
Cameron
Vector (Techlok, Optima)
FMC
Vetco
Vector (SPO)
ReFlange/Oceaneering (RCon)
Oceaneeriong/ReFlange
Aker Kvaener
Destec (Desflex)
Destec (G-Range, GSB)
LTS
LTS
… and others
FMC
- Compact Flange:
Oil States Industries
… and others
Aker Kvaener
… and others
- 111 Generally, three diverless subsea pipeline connection methods have been used in the
offshore industry. These methods are:
•
Pull-in Connection
•
Vertical or Horizontal Jumper Connection
•
Stab and Hinge-over (S&HO) Connection
The pull-in connection is a cost-effective method for both 1st end and 2nd end
connections. However, this method is known to take more offshore time than jumper
connection due to subsea pull-in operation.
Both vertical and horizontal jumper connections have been widely used for 2nd end
connection. The vertical jumper connection is more attractive than the horizontal jumper
connection because of easy installation and competitive hardware tool cost. However,
the abrupt vertical elevation difference by the vertical bends may cause a hydrate
formation (slug). The disadvantages of the horizontal jumper are difficulty in adjusting
misalignment and possible residual tension on the pipe due to horizontal stroking.
The stab and hinge-over connection is ideal for 1st end connection because of easy and
simple installation without any other pipe lay initiation support. The material and
fabrication cost may be higher but its offshore installation time is less than the jumper
connection.
Figures 15.3 through 15.6 illustrate each tie-in method. Table 15.2 summarizes the
advantages and disadvantages of each tie-in system.
- 112 -
Figure 15.3
Pull-in Connection Method
(by Aker Kvaener)
- 113 -
Figure 15.4
Vertical Jumper Connection Method
(by FMC (top) and Aker Kvaner(bottom))
Inverted “U” Shape
“M” Shape
(1)
FLOWLINE
Flexible Pipe with Goose Neck
(1) The connector module is lowered
by guide wire.
(2) The module is landed onto the
manifold hub.
(3) ROV makes up the connection
using hot-stab on torque tool.
GUIDE WIRE
(2)
(3)
- 114 -
Figure 15.5
Horizontal Jumper Connection Method
(by FMC)
(JSS (Jumper Stroking System) by ABB)
- 115 -
Figure 15.6
Stab and Hinge-over Connection Method (by OSI)
(1) Connector assembly is lowered.
(3) Connector assembly hinges over.
(2) Connector assembly lands in receiver structure.
(4) ROV makes the connection.
- 116 -
Table 15.2 Pros and Cons of Each Connection Method
Tie-in
Method
Pull-in
Connection
Vertical
Jumper
Connection
Horizontal
Jumper
Connection
Stab and
Hinge-over
Connection
Advantages
Disadvantages
- No jumpers/PLETs required
- Less connections – lower leak risk
- Deflect-to connect for 2nd end tiein
- Direct pull-in connect for 1st and
2nd end tie-ins
- Need to hold the pipeline installation
vessel until the tie-in is made
- Lengthy installation (pull-in) time
- Surface or subsea pull-in winch or
sheave required
- ROV docking space required
- Ideal for 2nd end connection
- Easier installation than horizontal
jumper connection
- PLET/jumper fabrication and sling
required
- Vertical bends may cause slug flow
problems
- Ideal for 2nd end connection
- No (vertical) bends required
- Provide optimal flow to prevent
hydrate formation (slug)
- PLET/jumper fabrication and sling
required
- Jumper might be in tension due to
horizontal stoking
- Hard to adjust misalignment
- Ideal for 1st end connection and
lay-away without initiation support
- Eliminate jumper/PLET for 1st end
lay-away
- Short installation time (simple
tooling required)
- Connection base with receptacle to be
installed first
- Low flexibility in installation sequence
- High material/fabrication cost
- 117 To make deepwater connections, several tools and systems are required in addition to
connectors. Followings are typical tie-in tools required for deepwater diverless tie-ins:
•
ROV
•
ROV running tool, seal replacement tool, actuator, etc.
•
Pull-in skid with winch (for pull-in connection)
•
Alignment funnel & sleeve (for jumper connection)
•
ROV control panel (for Collet connector)
•
Stab pin unit & receptacle base (for stab & hinge-over)
Many connector manufacturers and installation contractors offer their connection tools
and systems. The tie-in systems available for pull-in connection include:
•
DMaC (Diverless Maintained Cluster) by Subsea Offshore
•
UTIS (Universal Tie-in System) and ROVCON (ROV Connection) by FMC
•
DFCS (Diverless Flowline Connection System) by Sonsub
•
McPAC (McEvoy Pull-in And Connection) by Cameron
•
ICARUS by ABB
•
RTS (Remote Tie-in System) and BBRTS (Big Brother RTS) by Aker Kvaener
•
Flexconnect II by Technip, and many others
All systems above can make connections using either clamp or collet connectors, except
McPAC and ICARUS which only can use clamp connectors.
Figure 15.7 shows the pull-in connection systems offered by industry.
There exist many tie-in systems available for jumper connection and S&HO connection
as listed below. Figure 15.8 shows some systems available for these connections.
•
BRUTUS by Sonsub for horizontal jumper connection
•
VCS (Vertical Connection System) and GHO (Guide and Hinge-over) system by Aker
Kvaener
•
STABCON (Stab and Connect) connection system by FMC for horizontal jumper
connection
•
S&HO system by OSI, and many others
- 118 -
Figure 15.7
Pull-in Connection Systems
Subsea DMaC
Sonsub DFCS
FMC ROVCON
ABB Icarus
Technip Flexconnect II
Aker Kvaerner RTS
- 119 -
Figure 15.8 Other Connection Systems
Sonsub Brutus
(Horizontal jumper connection)
Aker VCS
(Vertical jumper connection)
FMC STABCON
(Horizontal jumper connection)
OSI S&HO System
- 120 References
[1]
FMC Technologies, Subsea Tie-in Systems Catalogue,
www.fmctechnologies.com/subsea
[2]
Destec Engineering Ltd., Compact Flange and G-Range Pipe Connectors
Catalogue, www.destec.co.uk
[3]
Technip Flexconnect II Presentation, 2006
[4]
Vetco, Vertical Clamp Connection System – VCCS Presentation, 2006 and
www.vetcogray.com
[5]
Aker Kvaener, Subsea Tie-in, Tools and Connection Systems Catalogue,
www.akerkvaener.com
[6]
Cameron Vertical Connection (CVC) System Catalogue, www.c-am.com/contents/products
[7]
MATIS Remote Flange Connection System, Stolt Offshore Limited, Subsea
Conference 2001
[8]
ReFlange A-CON Variable Alignment Connector Catalogue
[9]
Vector Optima Subsea Connector Catalogue, www.vectorint.com
[10] KOSCON Tie-in Systems, Kongsberg Offshore
[11] Framo RL Connector Technical Bulletin, 1999, Framo Engineering AS
[12] Brutus – Horizontal Jumper Connection System, Presentation by Sonsub
[13] The ICARUS Tie-in System, Outline Description, ABB Offshore Systems AS, 1999
[14] The HydroTech Diverless Collet Connector System Catalogue, Oil States
Industries, Inc.
[15] LTS Compact Flange Presentation, www.ltsusa.com
[16] Morgrip Diverless Technology, Repair Connector Presentation by Hydratight
Sweeney
- 121 -
16
UNDERWATER WORKS
To perform subsea works such as tie-ins, inspections, and repairs, underwater works are
required. In shallow waters, divers using air or helium gas can do the underwater works
but in deepwaters special devices are required such as saturation diving chamber
(SDC), atmospheric diving suit (ADS), remotely operated vehicle (ROV), and
autonomous underwater vehicle (AUV).
•
Surface diving - air diving (O2), 0-120 fsw, 120-180 fsw for short simple task
•
Gas diving - 10% to 16% O2 balanced helium, 120-180 fsw, 180-300 fsw for short
simple task. Helium is better than nitrogen and lowers decompression sickness
(bends) incidents
•
Saturation diving - 180-650 fsw , divers remain under pressure for the duration of
the project. Divers are pressurized and de-pressurized slowly in a chamber (Figure
16.1)
•
ADS - ~1,200 fsw or deeper (2,200 fsw), divers works in atmospheric pressure in
ADS (Figure 16.2)
•
ROV/AUV - Deepwater or harsh environment, AUV is self propelled (no need for
power supply or communication cables) and useful for short duration underwater
survey.
Figure 16.1 Saturation Diving
Lower SDC (Saturation Diving Chamber)
- 122 -
Figure 16.2 ADS and ROV
ADS (~1,200 fsw)
ADS (~2,200 fsw)
ROV
Two main categories of underwater welding techniques are wet underwater welding and
dry underwater welding, both are classified as hyperbaric welding.
In wet underwater welding, shielded metal arc welding (SMAW or stick welding) is
commonly used, using a waterproof electrode.
In dry underwater welding, the weld is performed in a chamber filled with a gas mixture
sealed around the structure (pipeline) being welded. Gas tungsten arc welding (GTAW
or TIG welding) is commonly used, and where here high strength is necessary, dry
underwater welding is most commonly used. The dry underwater welding is very
expensive and takes long offshore time. Research for dry underwater welding at depths
of up to 1000 m is ongoing [1].
Certified welder-divers are required for underwater welding in accordance with the AWS
D3.6, Specification for Underwater Welding Specification for Underwater Welding, and
other weld-related activities.
References
[1]
[2]
http://en.wikipedia.org/wiki/Underwater_welding
Oceaneering website, www.oceaneering.com
- 123 -
17
OFFSHORE PIPELINE WELDING
Line pipes can be connected by mechanical connectors or welding. Threaded and
coupling (T&C) or pin and box connectors are used for drilling riser and top tensioned
riser connections. However, welding is more commonly used for offshore pipelines due
to its proven technology and lower cost than mechanical connectors. Advantages of
connectors are: use of high grade pipes (up to 125 ksi SMYS), fast make-up, no welding
(no heat-affected zone, no welding inspection), no field joint coating, etc. Disadvantages
of connectors are: high material cost, leak test for each connection, weak for torsion and
fatigue, etc. Integral connectors, without requiring twist the pipe or connector, have
been developed. The available integral connectors are Jetair PSC, Hydil 2000, OSI
Merlin, etc.
The maximum pipe grade which can be welded offshore is X-70. Pipe grade higher than
X-70 requires induction heat treatment which is impossible for continuous long pipeline
welding. The induction heat treatment is normally done in an oven so it is limited by the
welded products’ size and length.
There are diversity of welding processes such as solid state welding (resistance, cold,
friction, ultrasonic, etc.), soldering/brazing, and fusion welding. Soldering/brazing melts
only filler materials not base materials. However, the fusion welding involves partial
melting of base material (called heat affected zone, see Figure 17.1). Electrical energy
(electrode) is commonly used for the fusion welding. The most widely used welding
types in offshore industries are listed next page and illustrated in Figure 17.2.
Figure 17.1 Heat Affected Zone
Welding filler
Heat affected zone
Base metal
Temperature
Original temperature
at base material
Fusion zone/weld pool
(base metal melt + filler melt)
Melting point of base metal
Temperature at which base material
microstructure is affected
- 124 •
SMAW or Stick Welding
Shielded Metal Arc Welding (SMAW) is frequently referred to as stick welding. The
flux covering the electrode melts during welding and this forms the gas and slag to
shield the arc and molten weld pool. The slag must be chipped off the weld bead
after welding.
•
GMAW or MIG Welding
Gas metal arc welding (GMAW) uses an arc between a consumable constant filler
metal electrode and the weld pool. Shielding is provided by an externally supplied
shielding gas. This method is also known as metal inert gas (MIG) welding or metal
active gas (MAG, i.e. carbon dioxide or oxygen) welding.
GMAW consists of a DC arc burning between a thin bare metal wire electrode and
the work piece. The arc and weld area are encased in a protective gas shield. The
wire electrode is fed from a spool, through a welding torch which is connected to the
positive terminal. The technique is easy to use and fast (high productivity) and there
is no need for slag-cleaning since no flux is used. The MAG process is suitable for
steel, low-alloy, and high-alloy based materials. The MIG process, on the other
hand, is used for aluminum and copper materials.
•
GTAW or TIG Welding
Gas tungsten arc welding (GTAW) is more commonly known as tungsten inert gas
(TIG) welding. It is an arc welding process that uses a non-consumable tungsten
electrode to produce the weld. The electrode used in GTAW is made of tungsten,
because tungsten has the highest melting temperature among metals. As a result,
the electrode is not consumed during welding, though some erosion (called burn-off)
may occur.
GTAW is most commonly used to weld thin sections of stainless steel and light
metals such as aluminum, magnesium, and copper alloys. The process is known for
creating stronger and higher quality welds than SMAW and GMAW. However,
GTAW is comparatively more complex and difficult to master. It is also significantly
slower than most other welding techniques.
- 125 -
Figure 17.2 Welding Types
SMAW, “Stick”
(Shielded metal arc welding)
ƒ In-continuous
consumable weld
ƒ Good for C-Mn only
ƒ Simple and portable
ƒ Slow
ƒ Slag and rough surface
ƒ No good for root welding
GMAW, “MIG”
(Gas metal arc welding)
GTAW, “TIG”
(Gas tungsten arc welding)
ƒ Continuous consumable weld
ƒ Non-consumable weld
ƒ Good for C-Mn and 13Cr
ƒ Good for all C-Mn and
CRAs
ƒ Fast, automatic- most efficient
ƒ Good for high strength
material
ƒ Commonly used for pipeline
welding
ƒ Good for root welding
ƒ Highest quality and cost
ƒ Good for thin material
ƒ Slow and high skill factor
- 126 Each welding should be examined for its completeness and quality by non-destructive
test (NDT). Generally four (4) NDT methods are widely used in welding inspection as
shown in Table 17.1.
Table 17.1 Non-Destructive Test
Radiography Test
Ultrasonic Test
Magnetic Particle
Dye Penetrant
X-ray/gamma-ray
passes through pipe
to film
Mechanical vibration
emitted, reflected,
and received
Detect disturbed
magnetic field
Detect by dye
penetration
Detects volumetric
defects, porosity,
and concavity
Detects planar
defects and lack of
fusion
Detects surface
and near-surface
cracks
Detects surface
cracks of
stainless steels
Safer than
Radiography
Figure 17.3 shows each inspection NDT method and its principals. The radiography test
is commonly used to find defects (such as voids and cracks) but it can not show the
depth of the defects (see Figure 17.3 (a)). Therefore automatic ultrasonic test (AUT) is
used to check the exact size of the defects, as necessary.
Figure 17.3 Non-Destructive Test
Radiation
Void
Specimen
(pipe)
Film after Processing
(a) Radiographic Test (RT)
- 127 -
Figure 17.3 Non-Destructive Test (continued)
(b) Automatic Ultrasonic Test (AUT)
(c) Magnetic Particle Test (MPT)
A. Sample before testing
B. Liquid penetrant applied
C. Surplus wiped off leaving
penetrant in crack
D. Developer powder applied,
dye soaks into powder
E. View colored indications, or
UV lamp shows fluorescent
indications
(d) Dye (Liquid) Penetrant Inspection (DPI)
- 128 References
[1]
Technip Presentation on Offshore Welding Methods
[2]
Field Welding Inspection Guide,
http://www.dot.state.oh.us/testlab/StructuralSteel/Field-Welding-InspectionGuide.pdf
- 129 -
18
PIPELINE PROTECTION – TRENCHING AND BURIAL
18.1
Soil Properties
The Unified Soil Classification System defines soils such as:
ƒ
ƒ
ƒ
Gravel
Sand
Silt & Clay
76.2 mm to 4.75 mm
4.75 mm to 0.075 mm
< 0.075 mm
Sand soils are defined by friction angle among solids and cohesive clay soils are defined
by shear strength as in Table 18.1, per DNV RP-F105, “Free Spanning Pipelines,” 2006.
Table 18.1 Soil Properties
Submerged Weight, γsub
Angle of Friction, ϕ
Shear Strength, Su
(kN/m3)
(Degrees)
(kN/m2)
Loose sand
8.5 – 11.0
28 - 30
-
Medium sand
9.0 – 12.5
30 - 36
-
Dense sand
10.0 – 13.5
36 - 41
-
Very soft clay
4.0 – 7.0
-
< 12.5
Soft clay
5.0 – 8.0
-
12.5 – 25
Firm clay
6.0 – 11.0
-
25 - 50
Stiff clay
7.0 – 12.0
-
50 – 100
Very stiff clay
10.0 – 13.0
-
100 – 200
Hard clay
10.0 – 13.0
-
> 200
Soil Type
Soil stiffness or soil spring constant is widely used in pipe-soil interaction problems. The
static soil stiffness is governed mainly by the maximum reactions. The dynamic soil
stiffness is governed by the unloading and re-loading cycles. The soil stiffness should
be computed for each loading direction, as required: vertical, axial, and lateral direction.
- 130 The static vertical stiffness is a secant stiffness representative for pipeline penetration
condition. If no data are available, use following values in Table 18.2 for the static
vertical stiffness per DNV RP-F105.
Table 18.2 Static Vertical Soil Stiffness
Soil Type
Loose Sand
Medium Sand
Dense Sand
Stiff Clay
Very stiff Clay
Hard Clay
Very Soft Clay
Soft Clay
Firm Clay
Kv (kN/m/m)
250
530
1350
1000-1600
2000-3000
2600-4200
50-100
160-260
500-800
Static vertical soil stiffness, Kv (kN/m/m), can be computed by:
KV =
z=
Ws
z
Ws 2
49 Do Su 2
= Pipe submerged unit weight (kN/m)
= Pipe embedment (m)
= Pipe outside diameter (m)
= Undrained soil shear strength (kN/m2)
Where, Ws
z
Do
Su
For example, Ws = 8.5 kN/m, Do = 1.22 m, Su = 4.0 kPa;
z=
8.5 2
49 × 1.22 × 4.0 2
KV =
= 0.076 m
8.5
= 112 kN/m/m (∴ very soft clay)
0.076
- 131 The above formula is modified from the 1995 OMAE paper [1]. Please see references
[2] to [4] for more information on soil stiffness.
18.2
Trenching and Burial
The offshore pipelines are trenched for such conditions and requirements as:
•
Physical protection from anchor dropping or trawl dragging (see Figure 18.2.1)
•
On-bottom stability
•
Approval authorities
The open trench could be covered by natural sedimentation depending on soil conditions
and currents near sea bottom. However, backfilling after the trenching or burial is
required for additional protection and thermal insulation purposes.
Figure 18.2.1 Fishing Trawl
Trenching equipment should be selected based on sea floor soil conditions. Followings
are available trenching equipment in the industry (also see Figure 18.2.2):
•
Ploughing – all types of soil
•
Jetting –sand and soft clay
•
Mechanical digging & cutting – stiff clay and rock
•
Dredging – all types of soil
- 132 -
Figure 18.2.2 Trenching Equipment
(a) Plough
(b) Water Jet Trencher
(c) Mechanical Trencher
(d) Dredger
- 133 A mass flow excavation (by suction or blow out the seawater) has been developed by
GTO [5] and Rotech [6]. Generally, soils in the range of 25 to 50 kPa strength are well
within the economical working range of the mass flow excavation tools. Any soils above
80kPa require high pressure Jetting to break up the conglomerated material which will
then need to be removed by sand pump, or mechanical means. Soils above 500 kPa
need mechanical means such as plows or dredgers.
Figure 18.2.2 Mass Flow Excavators
GTO ROV Suction Dredger [5]
Rotech Mass Flow Excavator [6]
- 134 Burial could be done by backfill the soil by cutting each top side of the open trench (see
Figure 18.2.3) using the same jet trencher used for trenching.
Figure 18.2.3 Backfilling
Required
burial
depth
Cut
section
Without burial, pipelines can be covered with rocks or concrete mattress (see Figure
18.2.4). This method is good for a pipeline laid on a hard rock sea bottom which is difficult
to be buried.
Figure 18.2.4 Rock Dumping (top) and Mattress Covering (bottom)
- 135 -
References
[1] “A Soil Resistance Model for Pipelines and Placed on Clay Soils,” Verley, R. and
Lund, K.M., OMAE paper, 1995
[2]
Free Spanning Pipelines, DND RP-F105, 2006
[3]
Guidelines for the Design of Buried Steel Pipe, ASCE , July 2001
[4]
SPAN User’s Manual (Rev. 9.2), Southwest Applied Mechanics, Inc.
[5]
http://www.gto.no/go/gto-technology/gto-rov-dredge for GTO ROV suction dredger
[6]
http://www.rotech.co.uk/www/subsea/sub_index.htm for Rotech mass flow
excavator
[7]
Trenching Considerations – Pipelines, www.oes.net.au/optc_pipelines.htm
[8]
Talon Deepwater Trenching System Brochure, Stolt Offshore
[9]
Fred Hettinger and Jon Machin, Cable and Pipeline Burial at 3,000 Meters, Oceans
2005
[10] R.D. Koster, Trenching of Offshore Pipelines and Cables using the SeaJet
Trencher, Ingeokring Newletter, Vol. 9 No. 1, 2003
[11] Palmer, A.C., “The Speed Effect in Seabed Ploughing,” Fourth Canadian
Conference on Marine Geotechnical Engineering, 1993
[12] P.G. Allan, “Geotechnical Aspects of Submarine Cables,” IBC Conference on
Subsea Geotechnics, 1998
[13] Soil Machine Dynamics Ltd Hydrovision website, www.smdhydrovision.com
[14] Advanced Multipass Plough Spread – AMP5 CTC Marine Projects Ltd. Website,
www.ctcmarine.com
- 136 -
- 137 -
19
PIPELINE SHORE APPROACH AND HDD
Pipelines transport gas or oil from offshore platforms to onshore storages or refinery
facilities. Also, pipelines are used to transport onshore gas or oil to offshore for
offloading to a shuttle tanker. Either case, the pipeline needs to cross the coastal lines.
If no environmental concerns exist, the most cost effective beach crossing method is an
open cut using dredge or trencher. If the beach crossing area is an environment
sensitive area, such as oyster field, turtle shelter, coral (tour) area, etc., and excessively
strong current occurs, horizontal directional drilling (HDD) is recommended.
Figure 19.1 shows a pipeline initiation from beach by using an open cut method. The
sheet piles are installed both sides of the trench to protect the trench from backfilling
during pipeline pulling operation.
Figure 19.1 Shore Approaching by Open Cut Method
Pullhead
- 138 The HDD is used to install pipeline beneath obstructions, such as rivers or shorelines. It
is considered the most effective environmental conservation method, but more
expensive than open cut & backfill method (see Figure 19.2).
Figure 19.2 Shore Crossing HDD
HDD is not suitable for all types of soil. Depending on soil types, the HDD time and cost
vary significantly (references [1] & [2]).
• Clay or sand:
Good to excellent
• Gravelly sand: Marginally acceptable
• Sandy gravel:
Questionable
• Gravel or rock: Unacceptable
Figure 19.3 shows the HDD sequence. The entry and exit angles are varied due to soil
types but typically less than 10 degrees from horizontal plane. The drilling mud used
during drilling operation penetrates into the soil and pastes the drilling hole surface, to
prevent collapse of the drilling hole.
HDD contractors include:
•
HDI (Horizontal Drilling International)
•
Mears
•
Laney Directional Drilling
•
Nacap, etc.
- 139 -
Figure 19.3 HDD Sequence [3]
- 140 References:
[1]
[2]
[3]
Installation of Pipelines by Horizontal Directional Drilling, An Engineering Design
Guide, PRCI (Pipeline Research Council International, Inc.), April 1995
Guideline, Planning Horizontal Directional Drilling for Pipeline Construction,
CAPP (The Canadian Association of Petroleum Producers), Sep 2004
DCCA (Drilling Crossing Contractors Association) poster
- 141 -
20
RISER TYPES
Risers transport products from subsea wells, via flowlines, to topside facilities (import
riser) or topside facilities, via pipelines, to onshore facilities (export riser). There are
fixed static risers, free standing dynamic risers, or combination of both (called hybrid
riser). Risers are classified as follows (see Figures 20.1 and 20.2) due to material type
and its application:
•
Rigid pipe –
Fixed (clamped) riser
J-tube riser
Fixed (clamped) catenary riser
Top tension riser (TTR)
Steel catenary riser (SCR)
•
Rigid + Flexible –
Hybrid riser
•
Flexible pipe –
Simple catenary riser
Lazy wave riser (with distributed buoys)
Pliant wave riser (chain anchored lazy wave)
Steep wave riser (vertical connection at seabed)
Lazy S riser (with an arch buoyancy structure)
Pliant S riser (chain anchored lazy S)
Steep S riser (vertical connection at seabed)
The steep wave (or S) riser is suitable when seabed space is limited. The pliant or
compliant riser is regarded as a hybrid of lazy and stiff wave (or S) risers.
The hybrid riser uses a rigid pipe for the vertical free standing portion and a flexible pipe
for the near surface dynamic motion region. Top tension riser is used to hold a vertical
riser when the well is underneath the floating structure. A pre-tension is applied to the
riser, so the riser pipe will not be in compression when the floating structure moves
down. Figure 20.3 shows hydropneumatic tensioner of which the piston cylinder in each
tank work like a shock absorber of automobile.
Bend stiffener is placed at flexible pipe end to increase the pipe stiffness and thus to
prevent fatigue damage caused by repeated bending (dynamic use). Bend restrictors
are installed at flexible pipe end to limit (restrict) the bend radius thus to prevent bending
buckling (static use).
- 142 -
Figure 20.1 Rigid Riser Types
Pre-installed riser with clamps
Subsea tie-in
Conventional
Fixed
J-Tube Riser
(Pulling the riser through preinstalled oversized J-tube)
Clamped
Catenary
Riser
SCR
(Steel Catenary Riser)
TTR (Top Tension Riser)
Hybrid Riser
- 143 -
Figure 20.2 Flexible Riser Types
Figure 20.3 Riser Top Tensioner
- 144 References:
[1]
Pipeline Riser System Design and Application Guide, PR-178-622, PRCI
(Pipeline Research Council International, Inc.), 1987
[2]
Ruxin Song and Paul Stanton, “Deepwater Tie-back SCR: Unique Design
Challenges and Solutions,” OTC 18524, 2007
[3]
API RP-2RD, Design of Risers for Floating Production Systems (FPSs) and
Tension-Leg Platforms (TLPs), 1998
[4]
DNV OS-F201, Dynamic Risers, 2001
[5]
Brian McShane and Chris Keevill, “Getting the Risers Right for Deepwater Field
Developments,” Deepwater Pipeline and Riser Technology Conference, 2000
[6]
K.Z. Huang, “Composite TTR Design for an Ultradeepwater TLP,” OTC Paper
#17159, 2005
[7]
A.C. Walker and P. Davies, “A Design Basis for the J-Tube Method of Riser
Installation,” Journal of Energy Resources Technology, Sept. 1983
- 145 -
21
RISER DESIGNS
Riser designs should be done per API RP 2RD - Design of Risers for Floating
Production Systems (FPSs) and Tension Leg Platforms (TLPs). The general procedures
are as follows:
•
Riser type and material selection
•
WT sizing
•
Static analysis
•
Dynamic vortex induced vibration (VIV) analysis
•
Fatigue analysis
•
Interference analysis
Steel riser is stiff, but if its length (L) is very long and the elastic stiffness (EI) is very
small), the steel riser can be treated as a catenary (the word originated from chain).
L
Catenary if
> 5,
C
⎛ EI
where C = ⎜⎜
⎝ Ws
⎞
⎟⎟
⎠
1/3
= characteristic length
The 16” OD x 0.684” WT pipe in 3,000 ft water depth will behave like a catenary, as
shown below.
⎛ EI
C = ⎜⎜
⎝ Ws
⎞
⎟⎟
⎠
1/3
⎛ 29,000,000 × 967 ⎞
=⎜
⎟
22.6/12
⎝
⎠
1/3
= 2,460 in = 205 ft
L 3,000
=
= 14.6 ⟩ 5 ∴ Catenary
C
205
The catenary formula is as below:
⎛x⎞
Y = a cosh ⎜ ⎟
⎝a⎠
T
a= H
Ws
Where,
TH is horizontal bottom tension (residual)
Ws is submerged pipe weight
- 146 The horizontal pipe tension is constant along the water depths, and can be estimated by
top tension multiplied by sin α, where α is the hang-off angle at surface. Converting the
above formula to obtain a free hanging catenary riser configuration gives;
Top tension, T = TH + Ws Y = T sinα + Ws Y =
Ws Y
1 − sinα
Bottom tension, TH = T sinα
Catenary constant, a =
TH
Ws
Riser free span length to touchdown, S = Y 1 + 2
a
Y
⎛S⎞
Horizontal distance to touchdown, X = a * sinh −1 ⎜ ⎟
⎝a⎠
If a riser pipe of 22.6 lb/ft submerged weight is installed with a 10-degree hang-off angle
in 3,000 ft of water;
Top tension, T =
Ws Y
22.6 × 3,000
= 82.0 kips
=
1− sinα
1− sin10 o
Bottom tension, TH = T sinα = 82 × sin10 o = 14.2 kips
Catenary constant, a =
TH 14.2 × 1,000
=
= 630.41
Ws
22.6
Riser free span length to touchdown, S = Y 1+ 2
a
630.41
= 3,000 1+ 2
= 3,575 ft
Y
3,000
⎛S⎞
⎛ 3,575 ⎞
Horizontal distance to touchdown, X = a * sinh −1 ⎜ ⎟ = 630.41* sinh −1 ⎜
⎟ = 1,536 ft
⎝a⎠
⎝ 630.41 ⎠
The above equations can be used to estimate J-lay configuration – top and bottom
tensions, touchdown point distance from the vessel, etc.
- 147 The touchdown area of the catenary riser is subject to fatigue damage due to its
movement against sea bottom as the host platform moves. To avoid this problem,
especially in harsh environment, flexible pipe is adopted using intermediate buoyancies
attached on the pipe. The slack of the flexible pipe absorbs the platform’s motions.
Dynamic VIV and Fatigue could be an issue when we design a dynamic riser. DnV and
API fatigue curves can be used for the fatigue damage check. Special care in pipe
procurement (tighter tolerance than line pipe specification) and welding procedures
should be addressed. Special pipe materials like titanium can be used for fatigue
sensitive areas. Strakes or fairings can be used to surpass VIV (see pictures in Section
12).
Determination of tension factor (TF) in top tension riser (TTR) design is very important.
Depending on host platform’s response amplitude operator (RAO) and riser pipe
properties, a 1.5 TF is commonly used in Gulf of Mexico. When the riser is in
compressed mode (platform moves down), the TF should not be less than 1.0. Also, the
TF should not be too big because when the platform moves up, an excessive tension will
occur on the riser.
Vortex induced motion (VIM) or interface with other risers or mooring lines should be
checked during riser designs. Also, the riser constructability needs to be evaluated in
early stage.
- 148 References:
[1]
Pipeline Riser System Design and Application Guide, PR-178-622, PRCI
(Pipeline Research Council International, Inc.), 1987
[2]
Ruxin Song and Paul Stanton, “Deepwater Tie-back SCR: Unique Design
Challenges and Solutions,” OTC 18524, 2007
[3]
API RP-2RD, Design of Risers for Floating Production Systems (FPSs) and
Tension-Leg Platforms (TLPs), 1998
[4]
DNV OS-F201, Dynamic Risers, 2001
[5]
Brian McShane and Chris Keevill, “Getting the Risers Right for Deepwater Field
Developments,” Deepwater Pipeline and Riser Technology Conference, 2000
[6]
K.Z. Huang, “Composite TTR Design for an Ultradeepwater TLP,” OTC Paper
#17159, 2005
[7]
A.C. Walker and P. Davies, “A Design Basis for the J-Tube Method of Riser
Installation,” Journal of Energy Resources Technology, Sept. 1983
- 149 -
22
COMMISSIONING AND PIGGING
22.1
Commissioning and Pre-commissioning
By definition, commission is a request to someone to perform a task (duty or mission).
The pipeline mission is to transport products safely, without failure or leak during the
design life. Commissioning (or startup) is to introducing the first product in the pipeline
system after the new system is installed. Prior to commissioning, the pipeline system
needs to be checked for cleanness, structure strength, leak proof, etc. These actions
are called pre-commissioning which include;
•
Debris removing, cleaning, gauging, and flooding (watering)
•
Hydrotesting and leak testing
•
Dewatering and drying
After installation, pipeline should be checked for internally cleanness and free from
debris such as welding rods, tools, etc. After debris-removal pig runs, a wire-brush
cleaning pig should run to remove more stubborn debris such as mill scale, weld bead
slag, etc. After cleaning the line, the pipeline should be checked for the pipe ID
reduction due to dent or flattening (increased ovality), by using a guage pig. The guage
pigs are fitted with aluminum plate of which diameter is typically 95% of the minimum
pipe ID. Now the pipeline is ready for hydrotesting and should be filled with filtered
water with biocide or corrosion inhibitor (for a long flood time). Prior to water pumping, a
pig is placed in front of the water to ensure removal of all the air in the line. To save
offshore operation cost, the above steps could be performed simultaneously using a
series of pigs (pig train) while flooding the line.
Each pipeline system, such as pipe segments, jumpers and PLETs, are hydrotested at
factory or confirmed by structural integrity test (SIT) or factory acceptance test (FAT).
However, the overall pipeline system, after completion of transportation and
connections, should be checked for its structural integrity (hydrotest) and leak proof (leak
test). The hydrotest pressure is set to be no less than 1.25 times of the maximum
allowable operating pressure (MAOP) or no more than 90% of the pipe SMYS, for at
least 8-hour holding time. The gas riser needs to be hydrotested for at least 1.5 times of
the MAOP. The leak test can be done with 1.1 times of the MAOP, for at least 1-hour
holding time.
- 150 After successful hydrotesting or leak testing, pipeline needs to be dewatered before
introducing the oil or gas. Dewatering pigs (or pig train) is used to displace water
efficiently. Air drying or vacuum drying is required for dry gas pipelines, but not required
for wet gas or oil pipelines. If pipeline is dewatered using a nitrogen gas, there is no
need to dry the pipeline.
During commissioning, pigs (pig train) are located in front of the first produced gas or oil,
to remove remaining air in the line and ensure that the line is fully filled with the product.
22.2
Pigging
Pig is a device used for cleaning a pipeline or separating fluids being moved down the
pipeline. It is inserted in the pipeline and carried along by pressurized flow of water, oil,
or gas. An intelligent pig is fitted with magnetic or ultrasonic sensors to detect corrosion
or defects in the pipeline. Pigging is performed during installation and operation for such
purposes as:
During Installation
•
Debris removing, cleaning, and gauging
•
Watering, dewatering, and drying
•
Commissioning
During Operation
•
Cleaning – wax/scale/condensate buildups removal
•
Inventory management – sweeping out batching products
•
Corrosion and scale control
•
Inspection – geometry (physical damage), corrosion, crack, leak detection
Miscellaneous
•
Decommissioning
•
Isolation
•
Recommissioning
- 151 During operation, pipelines should be pigged on a regular basis. Timing and frequency
for pigging is dependent on corrosion risk assessment and the production rate
fluctuation. Common pig types are as follows:
•
Utility pig –
foam, elastomer, mandrel (central metal body with various
components: discs, wires brushes, scraper blades, gauging
plates, etc.) to perform debris removing, cleaning, gauging,
watering, dewatering, drying, and batch separation of products
•
Gel pig -
made with highly viscous product for batching/separating, debris
removal, and dehydrating. Can be used alone (in liquid lines), in
place of batching pigs, or in conjunction with various types of
conventional pigs to improve overall performance by eliminating
the risk of a pig stuck.
•
Sphere pig -
foam or elastomer skin inflated with glycol and/or water normally
used to sweep liquids from gas lines
•
Inspection pig -
intelligent or smart pig using gauging plates and calipers to detect
geometry variations (dent, wrinkle, etc.), wall thickness variations,
cracks, corrosion, etc.
There are dual diameter pigs available to negotiate two distinct diameters, for example
8” and 10”. Typical pig speeds are in the range of 2 to 10 mph (1 to 5 m/s or 3 to 15 fps)
for oil line and 5 to 15 mph (2 to 7 m/s or 7 to 22 fps) for gas line [1]. Inspection pigs
may require slower speed, i.e. 0.5 m/s (1.5 fps).
Pipe bend for pigging should be at least 3D radius (bend radius equivalent to three pipe
nominal outside diameters) to allow intelligent pigs.
Flexible pipe’s corrugated carcass may allow bypass of fluid past the pig cups so a
double cup arrangement is recommended to reduce fluid by-pass. Appropriate pig
should be selected to avoid jam and stuck to the corrugated carcass gap.
Pigs could get stuck somewhere in the line during pigging. The main cause is that the
pig cups flip forward and the flow bypass the cups, so the pig is no longer pushed.
When this happens, another pig should run to push the stuck pig. When bidirectional pig
is stuck, it may be recovered by reversed flow. If the stuck pigs can not be recovered,
the pipeline section around the stuck pigs should be cut and replaced [1].
Pig launcher and receiver are used to send and receive pigs (Figure 22.2.1). Figure
22.2.2 shows debris and buildups removals. Variety Pig types are shown in Figure
22.2.3.
- 152 -
Figure 22.2.1 Pig Launcher and Receiver
(Source: www.ppsa-online.com [2])
Pig Launcher
(source: www.pipelineengineering.com [3])
Figure 22.2.2 Debris and Buildups Removal Pigging
- 153 -
Figure 22.2.3 Pig Types
(a) Utility pigs (Foam - Wire brush – disc)
(b) Sphere pig
(c) Intelligent pig
(SmartScan by GE, www.geoilandgas.com [4])
(d) Dual diameter pig
- 154 There are also isolation (plug) pigs available to plug the line temporarily during pipeline
installation or valve/damaged pipe replacement without interrupting the production or
minimizing the downtime. Figure 22.2.4 shows one application of plugs when risers are
being replaced while transporting the production from the other platforms.
Figure 22.2.4 Isolation Plug Application
(Source: www.tdwilliamson.com/media/video.html [5])
(Send plugs to riser bottom B Remove risers B Install new risers B Retrieve plugs)
References
[1]
Offshore Pipelines, Boyun Guo, et. al., 2005
[2]
An Introduction to Pipeline Pigging, PPSA (Pigging Products & Services
Association), 1995
[3]
www.pipelineengineering.com
[4]
GE Oil & Gas Website, WWW.GEOILANDGAS.COM
[5]
TDW Offshore Services, Remotely Operated Plugging Pig Service Catalogue,
www.tdwilliamson.com/media/video.html
[6]
Ralph Parrott and Edd Tveit, “The Use of Intelligent Plugs to isolate Operating
Pipelines for Construction and Maintenance Activity,” The Oil & Gas Review,
2005
- 155 -
23
INSPECTION
Subsea systems should be monitored or inspected regularly, internally and externally.
The inspection can provide such information as: geometry variation (dent, wrinkle,
buckle, etc.), wall thickness variation (metal loss), corrosion, crack, leak, etc.
The advantages and disadvantages of internal and external inspections are as follows:
•
Internal inspection:
Applicable for inaccessible (buried or concrete/insulation
coated) pipes. May have to shut-down the system to send
pigs. Pigs may be stopped or lost due to pipe buckle or
pressure loss due to large hole on the pipe.
•
External inspection:
Applicable for un-piggable line. No need to shut-down the
system. Good for partial suspicious area inspection, such as
manifold, jumper connection, riser, etc.
Self-crawling intelligent pigs have been developed to perform the In-line inspection (ILI)
without interrupting the production. The external inspections or integrity monitoring
systems are performed by ROV or tools mounted on the pipeline (Figure 23.1).
Magnetic and ultrasonic tools are commonly used to detect corrosion, crack, geometry
and wall thickness variations. Detecting a leak as early as possible will reduce the
environmental damage. The current leak detection systems available for subsea
pipelines are;
•
Ultrasonic -
transmit ultrasonic waves and receive/record reflected waves
•
Acoustics -
monitor/detect noise or pressure change being created by a
rupture or sudden leak
•
Dye detectors -
detect optical fluorescent leak visually by a laser beam
•
Fiber optics -
detect leaks by hydrophones, accelerometers, temperature
monitoring sensors installed on a distributed fiber optic cable
along the pipeline
•
Flow balance -
detect leak by monitoring volumetric flow rate, pressure, and
temperature
- 156 -
Figure 23.1 Internal and External Inspection Systems [1]
(The bristle-actuated pipeline tractor is powered through riser and operated by
brush modules that when actuated against each other provide a high pullcapability along the riser or pipeline.)
(a)
Internal Inspection
(Guided ultrasonic waves are used to screen long length of pipeline (several tens
of meters) for corrosion or cracks from a single transducer location.)
(b) External Inspection
- 157 The effective integrity monitoring and management planning allows the operator to
reduce uncertainties and risks associated with riser fatigue, corrosion build-up, hydrate
plug or wax formation conditions, etc.
The subsea integrity monitoring service providers include:
•
Genesis SIG (Subsea Integrity Group)
•
Come Monday, Inc.
•
IICORR (Integrity Inspection Corrosion)
•
Fugro Structural Monitoring (FSM)
•
2H Offshore
•
MCS
•
DeepSea Monitoring Solutions (DMS), etc.
References
[1]
Genesis SIG Website, www.genesis-sig.com
[2]
TDW Williamson Company Brochure
[3]
Offshore Pipelines, Guo, Boyun, et. al, Elsevier, 2005
- 158 -
- 159 -
24
PIPELINE REPAIR
Pipeline repairs may be required during pipeline installation or during operation. If a
pipeline is flooded (water penetrated due to buckling or damage) during pipe laying, the
best repair method is to reverse the lay operation and recover the defect point on the
vessel for replacement.
Shell’s Mensa project performed a 12-inch repair job at 5,000 ft water depth when the
pipe failed at a welding point due to excessive bending stress. Seven miles of pipe from
depths between 5,300 ft and 4,700 ft were recovered up the stinger by “reversed lay”
and later reinstalled [1]. The use of a repair clamp is another option for repair during
installation, if the defect point is small and precisely located.
Abandonment and recovery (A&R) procedures can be used to retrieve the damaged
pipeline section during pipelay. The process involves:
1)
2)
3)
4)
5)
Identifying the damage by ROV or diver
Cutting off the damaged pipe (by cutting saw or shaped charge explosive)
Installing a pipeline recovery tool (PRT)
Dewatering the pipe, if needed
Retrieving the pipe end to the water surface by “reversed lay”
The recovery tool may incorporate a dewatering mechanism with a subsea pig launching
apparatus (see Figure 24.1). During operation, there are generally two repair methods
available;
•
Clamp repair (see Figure 24.2)
•
Spool piece repair – on-bottom or surface lift
If the defect is isolated with no significant reduction in pipe diameter, such as a leak or
crack due to welding defect or pitting corrosion, a repair clamp method can be used. If
the pipe diameter is severely reduced or the damaged section is long, such as a
buckling rupture, a spool piece repair method must be used.
The basic tasks and procedures to complete a diverless clamp repair are as follows:
1)
2)
3)
4)
5)
Locate the damage
Prepare the work site (lifting the pipe by H-frame or jetting around the pipe)
Remove external coatings, if required
Lower, position, and install the clamp
Pressure test the clamp
- 160 -
Figure 24.1 Pipeline Recovery Tool (PRT)
(Picture taken from TD Williamson factory in Houston)
Figure 24.2 Diverless Repair Clamp [2]
- 161 The on-bottom spool repair method conducts all operations, cuts and connections at sea
bottom, without lifting the pipe to the water surface. An expandable horizontal spool or a
Z-shaped spool can be used like a horizontal jumper connection method.
The on-bottom spool repair procedures are as the following:
1)
2)
3)
4)
5)
6)
7)
8)
9)
Locate the damage section
Prepare the work site (lifting the pipe by H-frame or jetting around the pipe)
Cut the pipe in two places on either side of the damaged section
Put aside the cut section on the sea floor or retrieve to the surface
Remove coatings and clean each pipe end
Install connectors on each pipe end (test seal integrity)
Measure spool piece distance and fabricate spool with connectors
Lower, position, and connect the spool piece
Pressure test pipeline
The surface lift repair method has been used in shallow water repairs and is expandable
to deepwater repairs. This method requires pipe lifting to the surface, so a large vessel
to handle the pipe is required. The repair procedures are given below:
1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
11)
12)
13)
Locate the damage section
Prepare the work site (lifting the pipe by H-frame or jetting around the pipe)
Cut the pipe in two places on either side of the damaged section
Place a recovery tool (head) at the cut end of the damaged pipeline, dewater if
required
Lift the damaged pipeline to surface using a single point lifting method
Remove (cut off) damaged pipe section at the surface
Remove coatings and clean pipe end
Install a connector on a sled with a yoke
Lower the pipeline back to the sea bottom
Repeat for the second end of the pipeline
Measure spool piece distance and fabricate spool with connectors
Lower, position, and connect the spool
Pressure test pipeline
Figures 24.3 through 24.5 show clamp repair, on-bottom spool repair, and surface lift
repair sequence, respectively. Figure 24.6 shows shallow water pipeline repair
sequence, using a diver, forged stab end connectors, and a misalignment ball flanged
spool piece.
- 162 -
Figure 24.3 Clamp Repair Sequence [3]
Raise pipe and lower repair clamp
ROV opens clamp
ROV closes clamp and tests seals
Recover lift frames
- 163 -
Figure 24.4 On-Bottom Spool Repair Sequence [3]
Raise the pipe and cut the damaged
pipe section. Prepare pipe end for
grip & seal coupling installation.
Lower repair sled with a horizontal
coupling and a vertical connector
hub. ROV installs the coupling to the
pipe. Repeat for the other end.
Lower spool
piece. ROV
connects both
connectors and
tests seals.
Recover rigging.
- 164 -
Figure 24.5 Surface Lift Repair Sequence [3]
Raise the pipe and cut the damaged
pipe section. Install pipeline recovery
tool and lift the pipe to the surface.
Install repair sled with a horizontal
coupling and a vertical connector
hub at surface and lower to the
seabed. Repeat for the other end.
Lower spool
piece. ROV
connects both
connectors and
tests seals.
Recover rigging.
- 165 -
Figure 24.6 Pipeline Repair in Shallow Water
- 166 References:
[1]
OTC paper #8628, “Mensa Project: Flowlines,” 1998
[2]
QCS (Quality Connector Systems) Website, www.qualityconnectorsystems.com
[3]
Oil States Industries Inc. Website, http://oilstates.com
[4]
Harvey Mohr, “Deepwater Pipeline Connection and Repair Equipment,” The
Deepwater Pipeline Technology Conference, 1998
[5]
Alex Alvarado, “Gulf of Mexico Pipeline Failure and Regulatory Issues,”
Deepwater Pipeline and Riser Technology Conference, 2000
- 167 -
DEFINITIONS
(Not in alphabetical order. To be updated periodically.)
Hydrogen Induced Cracking (HIC): The mechanism begins with hydrogen atoms
diffusing through the metal. When these hydrogen atoms re-combine in minuscule voids
of the metal matrix to hydrogen molecules, they create pressure from inside the cavity
they are in. This pressure can increase to levels where the metal has reduced ductility
and tensile strength, up to where it can crack open so it is called hydrogen induced
cracking (HIC). High-strength and low-alloy steels, aluminium, and titanium alloys are
most susceptible.
Hydrogen embrittlement (or hydrogen grooving) is the process by which various metals,
most importantly high-strength steel, become brittle and crack following exposure to
hydrogen. Hydrogen cracking can pose an engineering problem especially in the context
of a hydrogen economy.
Hydrogen embrittlement can happen during various manufacturing operations or
operational use, anywhere where the metal comes in contact with atomic or molecular
hydrogen. Processes which can lead to this include cathodic protection, phosphating,
pickling, and electroplating. A special case is arc welding, in which the hydrogen is
released from moisture (for example in the coating of the welding electrodes; to minimize
this, special low-hydrogen electrodes are used for welding high-strength steels). Other
mechanisms of introduction of hydrogen into metal are galvanic corrosion, chemical
reactions of metal with acids, or with other chemicals (notably hydrogen sulfide in
sulphide stress cracking, or SSC, a process of importance for the oil and gas industries).
(Source: http://en.wikipedia.org)
Sweet or Sour Crude: The corrosivity of an oil and gas well is increased by the
presence of Cl (chloride) in water solutions, CO2 (carbon dioxide), and H2S (hydrogen
sulphide). The crude is considered sweet as long as H2S is not present. However, CO2
alone can cause high corrosion, since it is acidifying the solution and the corrosion is
further accelerated if Cl is present.
Sour Crude is defined when the partial pressure of H2S is above 0.05 psi. At higher
partial pressures, the corrosion rate on carbon steel is substantially increased by means
of making the water phase more acidic and by forming iron sulphide scale. Sulphide
stress cracking (SSC) is common in high strength steels.
- 168 The impurities (H2S, CO2, Cl, etc.) will need to be removed before the low quality sour
crude is refined into gasoline, thereby increasing the cost of processing. This results in a
higher-priced gasoline than one made from sweet crude oil. Thus sour crude is usually
processed into heavy oil such as diesel rather than gasoline to reduce processing cost.
HIPPS: High Integrity Pressure Protection System is an instrument based over pressure
protective system (OPPS) which is attractive for high pressure/high temperature (HP/HT)
developments where it is not possible to design the pipeline and risers to the full
wellhead shut-in pressure. The instrument can include series of fast acting (high
sensitivity) pressure relief valve, ESD (emergency shutdown valve), etc. There are less
than 6 subsea HIPPS worldwide (mostly in North Sea) and no HIPPS exists in the GOM.
PLEM and PLET: Pipeline end manifold (PLEM) is a sled equipped with multiple
connector hubs. If only one connector hub exists, it is called a pipeline end termination
(PLET). Midline sled is commonly called an in-line sled (ILS).
API Degree (gravity): The API (American Petroleum Institute) degree (or gravity), is a
measure of how heavy or light a petroleum liquid compared to water. If its API degree is
greater than 10, it is lighter and floats on water. API degree 10 equals to 1.0 specific
gravity (SG) of fresh water.
Although mathematically API gravity has no units (see the formula below), it is referred
to as being in “degrees”. API degree formula is derived using a hydrometer instrument
and designed so that most values would fall between 10 and 70 API gravity degrees.
(Source: http://en.wikipedia.org)
API degree =
Fresh water:
Heavy oil:
Medium oil:
Light oil:
141.5
SG at 60 o F
− 131.5
10 oAPI
<22 oAPI
22 oAPI – 31 oAPI
31 oAPI – 45 oAPI
- 169 Workover: Maintenance is performed during the service life of the well to ensure the
well produces at optimum levels. In addition to periodic maintenance, producing wells
occasionally require major repairs or modification, called "workover." Problems that can
result in a workover operation are: equipment failure, wellbore problems, and saltwater
disposal.
For problem wells, the remedial workover is performed to increase productivity, to open
new producing zones, or to eliminate excessive water or gas production. Examples of
these remedial workover operations are deepening, plugging back, pulling and resetting
liners, squeeze cementing, etc.
Ovality: Pipe out-of-roundness is the difference between largest diameter and smallest
diameter of a pipe (Dmax – Dmin). Ovality is the ratio between out-of-roundness and
average diameter (DNV definition). The ovality defined by API is half of the DNV ovality.
Ovality (DNV) =
Ovality (API) =
D max - Dmin
D max - Dmin
2 (D max - D min )
=
=
(Dmax + Dmin )/2 Dmax + Dmin
D av
D max - Dmin
D max + D min
If D nom = 16" , D max = 16.17" , D nom = 15.90" ,
Ovality (DNV) =
Ovality (API) =
2 × (16.17 - 15.90 )
= 0.017 = 1.7%
16.17 + 15.90
16.17 - 15.90
= 0.008 = 0.8%
16.17 + 15.90
- 170 RAO: Response amplitude operator (RAO) is used to represent the vessel or floating
structure’s six degree movements due to waves and wind, as below.
Heave
Yaw
Roll
Surge
Pitch
Sway
- 171 -