Appendix Q4 Technical Details Q4.1: Onshore Pipeline Design

233 Pages·2010·2.27 MB·English

Appendix Q4
Technical Details
Q4.1: Onshore Pipeline Design Review
Q4.2: Offshore Design Basis and Addendum No 1 to
Offshore Design Basis
Q4.3: Landfall Valve Installation Design Justification
and Overview
Q4.4: Appraisal of Alternative Configurations for the
LVI Safety Shutdown System
Q4.5: Aspects of Process Engineering Design of the
Corrib Production System
Q4.6: Reliability of Overpressure Protection Systems
for Offshore and Onshore Pipelines
Q4.7: Materials and Corrosion Management Premises
Q4.8: Assessment of Locally Corroded Pipe Wall Area
Q4.9: Assessment of Wet Gas Operation,
Internal Corrosion and Erosion
Q4.10: Denting and Puncturing Evaluation
Shell E & P Ireland Limited
CORRIB FIELD DEVELOPMENT PROJECT
REPORT
PROJECT No.
Corrib Onshore Pipeline EIS 052377.01
REF
APPENDIX Q4.1
CTR 349
ONSHORE PIPELINE DESIGN OVERVIEW No OF SHEETS
18
OFFICE CODE PROJECT No AREA DIS TYPE NUMBER
DOCUMENT No
05 2377 01 P 3 043
03 17/05/10 Issued for Planning Application JG GSW GSW JG
02 4/05/10 Issued for Comment JG GSW GSW JG
01 8/03/10 Issued for IDC JG GSW GSW JG
REV DATE DESCRIPTION BY CHK ENG PM CLIENT
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
CONTENTS
1 INTRODUCTION............................................................................................................4
2 GENERAL DESIGN PARAMETERS............................................................................4
2.1 Environmental Data.........................................................................................................4
2.2 Design Life.......................................................................................................................4
3 PIPELINE ROUTE..........................................................................................................4
3.1 Route Summary..............................................................................................................4
3.2 Glengad Headland..........................................................................................................5
3.3 Tunnel Under Sruwaddacon Bay....................................................................................5
3.4 Aghoos to Gas Terminal.................................................................................................5
3.5 Tie-in at Gas Terminal.....................................................................................................5
3.6 Stone Road......................................................................................................................6
4 ONSHORE GAS PIPELINE DESIGN...........................................................................7
4.1 Flow Rates.......................................................................................................................7
4.2 Pressures.........................................................................................................................7
4.3 Temperatures..................................................................................................................7
4.4 Fatigue.............................................................................................................................7
4.5 Gas Production................................................................................................................7
4.6 Design Pressure..............................................................................................................7
4.7 Selection of MAOP..........................................................................................................8
4.8 Hydrostatic Pressure Test...............................................................................................8
4.9 Design Location and Design Factor...............................................................................8
4.10 Corrosion Allowance.......................................................................................................8
4.11 Selected Wall Thickness.................................................................................................9
4.12 Materials..........................................................................................................................9
4.13 Field Welding...................................................................................................................9
4.14 External Coating..............................................................................................................9
4.15 Cathodic Protection.......................................................................................................10
4.16 Bends.............................................................................................................................10
4.17 Pigging...........................................................................................................................10
4.18 Crossings.......................................................................................................................11
4.19 Anchor............................................................................................................................11
4.20 Leak Detection...............................................................................................................11
5 OUTFALL DESIGN......................................................................................................12
5.1 General..........................................................................................................................12
5.2 Operational Parameters................................................................................................12
5.3 Codes and Standards...................................................................................................12
5.4 Outfall Design................................................................................................................12
6 UMBILICAL DESIGN...................................................................................................13
6.1 General..........................................................................................................................13
6.2 Umbilical Configuration.................................................................................................13
6.3 Connectors....................................................................................................................14
6.4 Service Fluids................................................................................................................14
6.5 Codes and Standards...................................................................................................15
6.6 Materials........................................................................................................................15
6.7 Tubing Material..............................................................................................................15
Page 2 of 18
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
6.8 LVI Offtake.....................................................................................................................15
6.9 Prevention of Failure.....................................................................................................16
6.10 Leak Detection...............................................................................................................16
7 FIBRE OPTIC CABLE DESIGN..................................................................................16
7.1 Communications............................................................................................................16
7.2 Supplementary Leak Detection.....................................................................................16
8 SIGNAL CABLE DESIGN...........................................................................................17
ATTACHMENT Q4.1A
Onshore Pipeline Stone Road Settlement Analysis For Pipelines And Services
Page 3 of 18
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
1 INTRODUCTION
The purpose of this document is to provide a design overview of the onshore gas
pipeline and associated service lines between the Landfall Valve Installation (LVI) at
Glengad through to the Bellanaboy Bridge Gas Terminal. The service lines comprise
the outfall pipeline, the three umbilicals, the fibre optic cable and the electrical signal
cable.
2 GENERAL DESIGN PARAMETERS
2.1 Environmental Data
Environmental data for the pipeline route is listed below, for years 1991 to 2000. Data
received from Met Eireann.
Max air temperature: 28 deg C
Monthly mean max temperature range: 8.9 to 18.2 deg C
Min air temperature: -5.5 deg C
Monthly mean min. temperature range: 3.9 to 12.2 deg C
Mean annual rainfall: 1269 mm
Max daily rainfall: 40 mm
Max hourly rainfall: 25.9 mm
Mean days (cid:149) 0.2mm rainfall: 254 days/year
Mean monthly wind speed range: 11.7 to 16.2 knots
Max wind speed (gust): 93 knots
2.2 Design Life
The pipeline, outfall pipeline, the umbilical and both the fibre optic and signal cables
have a design life of 30 years.
3 PIPELINE ROUTE
3.1 Route Summary
The selected route for the Corrib onshore pipeline is detailed in Chapter 3 and
illustrated in Appendix A Drawing DG103.
The onshore gas pipeline commences from the tie-in weld at the downstream barred
tee of the LVI. The pipeline then traverses the Glengad headland, in an east-south-
easterly direction for approximately 640m. The pipeline then proceeds ~4.9 km within a
dedicated tunnel in generally a south easterly direction beneath Sruwaddacon Bay.
The end of the Tunnel is situated near Aghoos. At Aghoos, the pipeline route turns in
an easterly direction for approximately 0.9km, traversing an area of blanket bog within
which it crosses an approximately 40m wide estuarine river channel. The route then
enters an area of forested bog (approximately 2.2km long) where it turns in a southerly
direction, at the crossing of the L1202, and continues to the Bellanaboy Bridge Gas
Terminal site.
Page 4 of 18
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
3.2 Glengad Headland
The section of route from the LVI to the Tunnel entrance along the Glengad Headland
is generally improved grassland and the gas pipeline will be buried with a minimum of
1.2m depth to the top of pipe. This section is traversed by a number of small ditches
with run-off from the surrounding terrain. Additional protection will be incorporated to
minimise any impact of scour or 3rd party damage.
The cross section of trench for the gas pipeline and the associated services within this
section is illustrated in Appendix A, Drawing DG604.
3.3 Tunnel Under Sruwaddacon Bay
A description of the Tunnel through Sruwaddacon Bay is provided in Chapter 5 and.
Appendix A, Drawings DG401 to DG404.
The Tunnel is a concrete segment lined construction of some 3.5m internal diameter.
The alignment of the Tunnel in Sruwaddacon Bay has been selected to meet the
hazard and risk assessment criteria set by the authorities and to minimise the impact
on the environment.
The pipeline and associated services will be installed individually in the Tunnel and the
cross section is illustrated in Chapter 5 Figure 5.5. On completion the Tunnel will be
fully grouted.
3.4 Aghoos to Gas Terminal
From the Tunnel exit near Aghoos, the pipeline transverses a 0.9km section of blanket
bog and then crosses the approximately 40m wide Leenamore river channel. From
there the route enters forested bog up to the road crossing (RDX1) of the L1202. From
the road crossing the route continues with a short section of forested bog and then
blanket bog to the boundary of the Gas Terminal.
Throughout this section the pipeline and associated services will be installed within a
stone road (refer Section 3.6). At the Leenamore crossing a specific crossing technique
will be adopted as detailed in Chapter 5 and illustrated in Appendix A Drawing DG703.
Similarly at RDX1 a specific road crossing method will be adopted as illustrated in
Appendix A Drawing DG701.
Throughout this section of the route, the gas pipeline will be buried to a minimum depth
of 1.2 m.
The cross section of the gas pipeline and the associated services within the stone road
is illustrated in Appendix A, Drawing DG601.
3.5 Tie-in at Gas Terminal
As the pipeline approaches the Gas Terminal boundary fence, the depth of cover will
be maintained at a minimum of 1.2m to the top of the gas pipeline. Within the Gas
Terminal site the pipeline crosses an internal site access road before rising above
ground for interconnection to the Gas Terminal isolation valves and pig receiver. Where
the pipeline rises above ground, an specially manufactured Isolation Joint will provide
electrical isolation between the Gas Terminal pipe work and the onshore pipeline
Cathodic Protection system. To minimise the forces imposed on the Gas Terminal
above ground pipe work a buried concrete anchor block will be installed before the
onshore pipeline rises above ground. (Refer Section 4.19)
The outfall pipeline, the umbilicals, the fibre optic cable and the signal cable will all
terminate at positions close to the gas pipeline pig receiver.
Page 5 of 18
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
The receipt facilities at the Gas Terminal are illustrated in Figure 3-1.
EEmmeerrggeennccyy
SShhuuttddoowwnn
SSyysstteemm
IIssoollaattiioonn
JJooiinntt
TToo PPiigg
2200””
FFrroomm RReecceeiivveerr//
LLVVII SSlluugg CCaattcchheerr
GGrroouunndd LLeevveell VVNN 00660011 EESSDDVV 11000011
AAnncchhoorr
OOnnsshhoorree PPiippeelliinnee TTeerrmmiinnaall PPiippee WWoorrkk
TTiiee--iinn PPooiinntt
Figure 3-1 Pipeline Facilities at the Gas Terminal
3.6 Stone Road
The method of construction of the stone road is presented in Chapter 5. The top layer
of peat turf is stripped and stored. The lower section is excavated and removed from
the site. The road is constructed by backfilling with stone to form the stable base within
which the onshore gas pipeline and services can be installed with the top of the gas
pipeline buried to a minimum depth of 1.2m. The ground surface above the stone road
is reinstated using the stored turfs.
As the stone backfill is carefully compacted, no movement of the stone road within the
peat is expected. The potential for movement of the stone road has been evaluated
and presented in Appendix M. The analysis established that there was no horizontal
movement of the stone road in the peat. Small changes in vertical movement may
occur and these have been quantified. To ensure that any such vertical movement
would not result in loss of containment from the gas pipeline and that the
displacements would not affect the services, an analysis was performed taking into
consideration the worst case vertical displacements that could be considered along the
route of the stone road.
The analysis established that the effects on the services were within the design
parameters and thus no consequential effects result from the worst case vertical
displacement. For the gas pipeline the calculations established that the resultant
pipeline stresses were 408 MPa and within the allowable limits stated by the respective
pipeline code. The highest values were identified as occurring during hydrostatic
testing of the onshore pipeline. (Refer Attachment Q4.1A for additional details)
To verify the integrity of the gas pipeline, with respect to ground movement within the
stone road, a movement monitoring programme will be adopted. This will involve short
term (during construction) and long term (post construction) high accuracy surveys
carried out regularly along the pipeline route to identify any indications of movement of
the stone road. GPS plates will be installed where appropriate to assist this monitoring.
As part of the movement monitoring programme, piezometers will be installed adjacent
Page 6 of 18
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
to the stone road to allow monitoring of groundwater levels. The frequency of
monitoring will be tailored based on the results of the ongoing monitoring. The
monitoring proposals are included in Appendix M2.
4 ONSHORE GAS PIPELINE DESIGN
4.1 Flow Rates
Design Flow Rate 350 MMSCFD (dry sales gas)
Maximum Flow Rate: 350 MMSCFD (dry sales gas)
4.2 Pressures
Design Pressure: 144 barg
Normal Operating Pressure (onshore section, at start of field life): 90 to 85 barg
Hydrostatic Test Pressure 504 barg
4.3 Temperatures
Maximum Design Temperature: 50oC
Minimum Design Temperature
20 inch pipeline from LVI to ~1100m downstream of the LVI -20°C
20 inch pipeline from ~1100 m downstream of the LVI to Gas Terminal -10°C
For design conditions at the Landfall Valve Installation refer to Appendix Q4.3.
4.4 Fatigue
Normal Diurnal Pressure Range: 90 to 85 barg
Number of Cycles Between Diurnal Pressure Range: 11000
Number of Cycles Between Design Pressure Range: 30
Pressure cycles in the pipeline will be recorded via the DCS at the Gas Terminal. This
data will be evaluated on an annual basis and the pressure cycles will be counted. The
actual pressure cycles will be compared with the allowable pressure cycles to assess
potential fatigue.
4.5 Gas Production
The Corrib field gas will be produced as water saturated gas with small quantities of
free water. Early years of production, including start-up, will require use of the
wellhead choke valves. Cooling of the gas subsea reduces the temperature to below
the hydrate formation point at normal operating pressure. Methanol is used during
start-up and in normal operation to prevent hydrate formation.
For information on well product composition, produced water and production profile
refer to Appendix Q4.2.
No operational blowdown of the gas pipeline is planned. If required under upset
conditions, a pipeline depressurisation procedure at the Gas Terminal will be
undertaken in such a manner so as not to induce hydrate formation.
4.6 Design Pressure
TAG recommended, following issue of the Advantica Independent Safety Review, that
the pressure in the onshore pipeline should be limited to no greater than 144 barg. This
Page 7 of 18
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
value of 144 barg was therefore selected as the design pressure for the onshore gas
pipeline.
4.7 Selection of MAOP
From the pipeline codes; the maximum allowable operating pressure (MAOP) is the
maximum steady state pressure at which a pipeline system is allowed to be
continuously operated. The MAOP is the sum of the static head pressure, the pressure
required to overcome friction loss and any required backpressure. Furthermore, the
MAOP shall not exceed the design pressure. In pipeline code I.S. 328 this is referred to
as the maximum operating pressure (MOP).
For the onshore pipeline the highest daily operating pressure at the LVI is expected to
be around 90 barg. Allowing a margin for the over-pressurisation protection trip settings
an MAOP of 100 barg has been established.
4.8 Hydrostatic Pressure Test
Prior to commissioning, the onshore pipeline will be hydrostatically tested to a defined
pressure at the lowest point of the pipeline. The test pressure will be maintained for a
period of 24 hours.
The hydrostatic test pressure for the onshore pipeline was established following the
recommendation from the Advantica and TAG reports and presented is in Appendix
Q5.3. This determined that the onshore pipeline Hydrostatic test pressure will be 504
barg. This is defined in the codes as a High-level hydrostatic strength test. Successful
completion of the test at this level demonstrates that any remaining defects are
considerably smaller than would fail at the operating pressure. It provides a rigorous
demonstration of a quantified safety margin that accommodates an allowance for
defect growth during service.
This hydrostatic test pressure is:
(cid:120) 5.6 times the daily operating pressure (90 barg)
(cid:120) 5.0 times the MAOP (100 barg)
(cid:120) 3.5 times the Design Pressure
4.9 Design Location and Design Factor
From the TAG recommendations following issue of the Advantica Independent Safety
Review, the classification of design location should be suburban which would be
consistent with the design of pipelines passing through more densely populated
suburban areas. In I.S. 328 this is defined as a population density exceeding 2.5
persons per hectare but not classified as central areas of highly populated towns and
cities. This is more stringent than the rural classification where the population does not
exceed 2.5 persons per hectare.
Subsequently the design factor for the onshore pipeline will be 0.3 (as defined in
pipeline code I.S. 328). This is further detailed in Appendix Q6.2.
4.10 Corrosion Allowance
From a detailed analysis of the potential for corrosion over the expected field life of the
project, an allowance of 1.0 mm was determined for the Onshore Pipeline. Refer to
Appendices Q4.7 and Q4.9.
Page 8 of 18
Corrib Onshore Pipeline EIS
Appendix Q4.1
Onshore Pipeline Design Overview
4.11 Selected Wall Thickness
The wall thickness of the onshore pipeline is determined in accordance with pipeline
code I.S. 328. It should be noted that each of the codes utilise the same principle of the
Barlow formula. However each code applies the formulae with subtle differences.
The factors comprising the Barlow formula are design pressure, pipe diameter, wall
thickness of the pipe, design factor and specified minimum yield strength of the pipe
(i.e. SMYS or the strength of the pipe material).
It is noted that a lower numerical value of Design Factor increases the wall thickness.
Also the higher the design pressure the higher the wall thickness.
By applying the design parameters to the Barlow formula gives a value of wall
thickness for pressure containment. Added to this are manufacturing tolerances (1mm)
and the corrosion allowance of 1mm giving a nominal pipe wall thickness of 27.1 mm.
4.12 Materials
The line pipe has been manufactured from carbon steel as specified in DNV pipeline
code DNV-OS-F101:2000. The specification includes the following main points:
(cid:120) SMYS: 485 N/mm2
(cid:120) Wall thickness manufacturing tolerance: +/- 1mm
(cid:120) Corrosion allowance: 1mm
(cid:120) Nominal Wall thickness (onshore section): 27.1mm (inclusive of 1mm corrosion
allowance)
(cid:120) Nominal outside diameter: 20”
4.13 Field Welding
The lengths of 20” dia onshore line pipe will be welded in the field by qualified welders.
Welding will be in accordance with the requirements of I.S.328:2003 and in particular
I.S. EN 12732.
4.14 External Coating
4.14.1 Linepipe
The factory applied external anti-corrosion coating protection for the onshore line pipe
is a three layer polypropylene systems (3LPP). This system comprises a high
performance fusion bonded epoxy (FBE) followed by a copolymer adhesive and an
outer layer of polypropylene which provides the toughest, most durable pipe coating
solution available.
4.14.2 Field joints
Where the line pipe sections are welded together in the field, the section of jointed pipe
at the weld is protected by an anti-corrosion coating termed field joint coatings. For the
onshore pipeline they take the form of a sleeve or wrap. This shrinks in the
circumferential direction under the influence of heat forming an adherent field joint
coating. The shrink sleeve consists of a polyolefin based backing with an adhesive
layer (mastic or hot melt) on one side. The shrink sleeve will be applied with a primer.
Page 9 of 18