pipeline design
TRANSCRIPT
1
Pipeline Design
This Offshore Pipeline System manual is prepared to cover the important aspects of pipeline designing,
construction, installing, testing, commissioning, operation and maintenance for the knowledge
development of pipeline engineers, operators and technicians alike. Only simple equations and
calculation are being used.
Learning Objectives
General design procedure for offshore pipeline and riser
Understanding the various forces acting on pipeline-Internal and External
Calculating strength, stability, buckling and spanning
Important points on pipeline routing, survey and mapping technique
Pipeline terminating on shore and tie-in
1.1 Overview of Pipeline Components
Subsea Pipelines are used for the transportation of offshore Hydrocarbons from one Platform to another
and or Platform to Shore
Pipelines are used for a number of purposes in the development of offshore hydrocarbon resources;
these include e.g.:
Pipeline is defined as the part of a pipeline system which is located below the water
surface at maximum tide (except for pipeline risers)
Pipeline may be resting wholly or intermittently on, or buried below, the sea bottom
Pipelines transporting oil and/or gas from subsea wells to subsea manifolds
Pipelines transporting oil and/or gas from subsea manifolds to production facility
platforms
Infield pipelines transporting oil and/or gas between production facility platforms
Export pipelines transporting oil and/or gas from production facility platform to
shore
Pipelines transporting water or chemicals from production facility platforms,
through subsea injection manifolds, to injection wellheads.
Offshore Pipeline pipes made out of carbon steel, alloy steel, stainless steel and duplex, flanges and
fittings of particularly high-yield grades and large OD dimensions to the FPSO conversion,
shipbuilding, ship repair and oil, gas and petrochemical industries
2 Offshore Pipeline Systems
Design Codes ASME B31.4
ASME B31.8
DnV 1981
Carbon Steel and High-Yield Alloy Steel Pipes Carbon steel and high-yield alloy steel pipes in the following specifications:
ASTM A106: ¼in to 24in OD seamless – all wall thicknesses
API 5L grade B/ASTM P1, P5, P9, P11, P22, P91, A53/X42/A333 Gr6: ¼in to 24in
OD seamless and 18in to 106in DSAW, LSAW and ERW
APL 5L - X52, X56, X60, X65 and X70: ¼in to 24in seamless in wall thicknesses
of up to 60mm; 18in to 106in DSAW and ERW
Stainless-Steel and Duplex Pipes Stainless-steel and duplex pipes in all grades and dimensions of ASTM A182.
Pipeline Components Any items which are integral part of pipeline system such as flanges, tees, bends, reducers and valves
Flanges There are wide ranges of flanges, including carbon steels, low-temperature alloys, high-yield grades,
stainless steels, super-stainless and exotic alloys are in the market; range of flanges includes the
following: SAE flanges – 3,000lb and 6,000lb rated
Plate flanges
Rings and sockets
Forged discs, caps and dished ends
Long weld-neck flanges
Seamless piped flanges
Nozzles (with and without radius)
Anchor flanges
Swivel-ring flanges
Customized flanges in line with customer specifications
Forged Fittings Forged fittings to BS3799 are available in carbon and low-temperature alloys, as well as stainless and
other materials upon request, and are 3,000#, 6,000# and 9,000# rated. The forged fittings are screwed
and socket weld with the following:
45° and 90° elbows
M/F street elbows
Tee pieces
Cross pieces
Full and half couplings
Caps and plugs – square, hex and round head
Hex bushes and nipples
Unions, screwed and socket weld – male/female
Weld bosses
Reducing inserts
Weldolets, sockolets, elbolets, latrolets and nipolets
All of our materials conform to NACE MR0175.
Pipeline Design 3
Butt Weld Fittings A full range of butt weld fittings, including the following:
Carbon, low-temperature alloys, exotic alloys; stainless and other materials are
available upon request
45° and 90° elbows (short and long radius)
Tees, equal and reducing
180° return bends (short and long radius)
End caps
Reducers, concentric and eccentric
Pipeline System An inter connected system of submarine pipelines, their risers, supports, isolation valves, all integrated
piping components, associated piping system and the corrosion protection system.
Subsea Pipeline Design Activities
Pipeline Sizing
Pipeline Material Selection
Pipeline Mechanical Design
Pipeline Stability Analysis
Pipeline Span Analysis
Pipeline Crossing Design
Pipeline Cathodic Protection System Design
1.2 General Design Procedures In general, the design of pipelines for offshore applications is considered in a broader perspective, such
as:
(1) Mechanical Design
(2) Metallurgical Design
Mechanical Design of Pipelines As we know, the pipelines are laid on the bottom of the seabed. The mechanical conditions of seabed
greatly affect the design of pipelines.
Factors that have to be considered for Mechanical design are:
(1) The water depth, water currents, and waves will have influence in pipeline design.
The oceanographic data may provide 1 year to 100 years history of extreme waves
and associated currents and its speed, wave heights, wave directions, tide data etc.
The water temperature’s maximum and minimum values will affect pipeline
operations through heat transfer.
(2) Sea floor conditions, obstructions, and hazards
The Geotechnical survey data may provide important information, such as seal
floor conditions, which may affect both pipeline’s mechanical design and
operations.
(3) Seafloor Bathymetry and pipeline Bathymetry
(a) Seafloor Bathymetry:
The soils on the seabed and its mechanical conditions will affect the stability of
the pipeline. It will also affect the pipeline routing, alignment and spanning the
pipeline underwater. The pipelines may sink below the seabed and get buried
into the subsea soil, affecting the heat transfer process of the pipelines. A study
of the soil mechanical properties is very much essential in subsea pipeline
design.
4 Offshore Pipeline Systems
(b) Pipeline Bathymetry:
The outlet of the pipeline carrying the flow should go upward and the water
depth at the pipeline outlet shall be shallower than at the inlet. This bathymetry
is preferred in order to avoid the severity of multiphase slug flow.
(4) Defining the Splashing Zones:
The splashing zone is the pipe or riser section that will be splashed by the surface
wave. Because of seawater splashes, the pipe or riser sections tend to have more
severe corrosion problems. Extra coatings are necessary at these points.
Metallurgical Design of Pipeline The general factors considered here as follows
(1) The type of fluid inside the pipeline-Corrosive or Non-corrosive?
(2) The flow design-Single phase or Multiphase?
(3) The PVT characteristics
(4) The Reservoir formation, performance, pressure & temperature, product profile and
sand concentration and particle distribution.
The metallurgy of pipeline materials plays an important role in handling fluids inside the pipeline.
Type of Fluid
(a) The seawater is salty and salty seawater is corrosive. The seawater contains high salt concentration.
The dissolved gases in this seawater like, oxygen, hydrogen sulfide, carbon dioxide would drastically
increase the seawater corrosively. Therefore, it is important to analyze the water compositions in
pipeline design and operations.
Flow Design
(b) Single phase flow: Referring to a flow or other phenomenon with only one component, normally oil,
water or gas inside the pipeline. A single phase oil or water does not change in density with decreasing
pressure, nor the viscosity because of flow conditions in pipeline.
Multiphase flow
(c) Referring to a flow with water, oil and gas flowing simultaneously inside the pipeline creating
potential problems such as:
Water and hydrocarbon fluids can form hydrate and block the pipeline,
Wax and asphaltene can deposit on the inside wall and block the pipeline
Corrosion in imminent in the presence of water and scaling formation may restrict
the flow.
Severe slugging may form inside the pipeline and can cause operational problems
to downstream equipment.
Fluid PVT Properties
(d) The pipeline design is greatly affected by the “PRESSURE”, “VOLUME,” and “TEMPERATURE”
properties of fluid being handled by the pipeline. The pipeline must be sized to transport fluid at
particular flow rate and at a particular pressure at the outlet, considering the various pressure drops
occurring from reservoir pressure to pipeline outlet pressure. A very important step in characterizing the
fluid in order to size the pipeline accurately to PVT parameters at different pressures and temperatures.
Reservoirs in consideration
(e) The pipelines cannot simply be sized to deliver the maximum production. The performance of the
reservoir over its field life must be taken into account. The flow rates vary at different stages of
reservoir field life.
(f) The Reservoir pressure and temperature can affect the pipeline operating pressure. Since the
reservoir pressure is directly related to the wellhead pressure, the pipeline beyond wellhead has to be
designed with special metallurgy, if there is high pressure and when the wellhead pressure is low, then
some artificial lift or gas-lift has to be employed for the fluid to flow.
Pipeline Design 5
(g) The Reservoir temperature also affect the pipeline design. Very high temperature, require a special
piping material, whereas at low temperature, we may require a thermal insulation or pipe-in-pipe design
is required.
(h) The oil flow rate will be low at the beginning of well operation, pick up speed within a short period,
sustain the production rate and after few years, the production rate will decline. If the pipeline is
oversized, the fluid flow inside the pipeline might become unstable at the declining phase of well
production. This may create problems like slug formation, excessive vibration and corrosion
(i) The sand production greatly affects inside of the pipeline material. Sand presence in the fluid flow
may result in pipeline erosion, fluid velocity to be increased to carry the sand out ‘ of the flow line and
sands may prevent the chemical inhibitors like corrosion inhibitors from adhering to the pipe inside
wall, thus reducing its effectiveness.
Stages of Pipeline Design
(a) Conceptual Engineering and feasibility study
(b) Basic engineering
(c) Detail engineering
Conceptual Engineering and Feasibility Study The conceptual formation for pipeline design should follow the procedures laid out below:
(a) Establish piping system requirement based on field conditions
(b) Evaluate and check if there are any constraints on the pipeline system design
(c) Identify the required interfaces with other systems
(d) Develop a comprehensive design data requirement
(e) Assess the construction methodology for entire pipeline systems
(f) Finalize the concept, removing any constraints
The feasibility study consists of:
(g) Evaluate Technical Options
(h) Eliminate Unviable Options
(i) Firming up of Process Facilities
(j) Develop Broad System Specifications
(k) Establish Project Cost
(l) Plan Project Implementation Scheme
Basic Engineering The Basic engineering decides about pipe size, material grade and provides design details in such a way
that an ordering information is available for procurement of pipeline and accessories. The following
points are also to be considered:
1. Finalize Process Scheme & Equipment Engineering
2. Environmental & Process Data Review
3. Pipeline Routing & Size Optimization
4. Establish Requirements for
a) Surveys and Investigations
b) Material of Construction
c) Preliminary Analysis
d) Construction, Testing and Commissioning
5. Develop Implementation Schedule
The safety point of view, the following points are also considered:
1. Environmental Parameter and Soil Data
2. Pipeline Stability
3. Shore Approaches
4. Trenching and Burial
5. Safety of Existing Facilities
6 Offshore Pipeline Systems
Detailed Engineering The design is completed in sufficient details to define the technical input for all procurement and
tendering process. The following points are to be considered:
1. Engineering Design Basis
2. Route Engineering & Surveys
3. Engineering analysis and Calculations
4. Specification and Job Standards
5. Engineering for Procurement
6. Drawings for Construction
7. Installation analysis and Procedures
1.3 Design for Strength
The design of pipeline strength in deep water application is a modern trend and all key pipeline design
issues should address the following:
(a) Strength design in shallow water application
(b) Strength design in deep water application.
(c) External pressure of the water on the pipeline
(d) Internal pressure of the fluid in the pipeline
Let us consider the strength of the pipes in deep water application. Most of the pipelines are installed
empty and the external pressure will induce a large load on the pipeline and can result in a different
mode of failures. When comparing the external pressure with internal fluid pressure during operation, it
is obvious that the external pressure still be larger than the internal pressure. As a consequence
additional failures can be anticipated. These failure modes are to be considered not only for pipe wall
thickness design, but also for on-bottom stability issues.
External Pressure Effect to the Wall Thickness Design
Figure A1
Pressure Effect on pipes
It can be seen from the above figure, that the behavior of the pipe crosses section due to external
pressure of water. During the installation, hydrostatic test and operation, the pipelines are subjected to
external pressure, internal pressure, bending moment and axial tension for shallow water application.
Pipeline Design 7
For the pipeline design in deep water, there are four failure modes are anticipated, namely:
(a) Design for internal fluid pressure
(b) Design for collapse due to external pressure
(c) Combined pressure
(d) Buckling strength
1.4 Design for Internal Fluid Pressure The internal fluid pressure can be identified as the one during operational pressure and during the
hydrostatic test pressure conditions. We have to determine the wall thickness for both and compare.
Wall Thickness Calculation Based on Internal Pressure The internal design pressure for a given wall thickness or the design wall thickness for a given (internal)
design pressure can be determined as follows:
2 x t x y x Fd x J x T Pd = (Pi – Pe) = --------------------------------------- Eqn.1 D
Or
Pd x D t = -------------------------------- Eqn.2
2 x y x Fd x J x T
Where, Pd = Internal design pressure,
= Pi – Pe (Internal pressure – external pressure)
t = Nominal or Minimum wall thickness,
y = Specified Minimum Yield Strength
Fd = Internal burst pressure design factor,
= 0.72 for pipelines under water, 0.50 for riser section
(as per ASME B31.4, 1989 and DnV 1981)
J = Longitudinal weld design factor, 1.0
T = Temperature de-rating factor, 1.0
D = Pipe outside diameter
Note:
Use of design nominal wall thickness vs design minimum wall thickness. As per
CSA (Canadian Standards Association)
For onshore pipeline, the thickness calculated by the above equation will be
“Nominal Wall Thickness”.
For Offshore pipeline, the thickness calculated by the above equation will be
“Minimum Wall Thickness”.
As per API Standard, the wall thickness calculated by the above formula will be
“Nominal Wall Thickness”
Therefore, a relationship exists between these two is:
Design Minimum Wall Thickness
Design Nominal Wall Thickness = --------------------------------------------------
0.92
8 Offshore Pipeline Systems
Wall Thickness Calculation Based on Hoop Stress (Thin Wall Pipe) The hoop stress, at any given pressure, is defined by:
Pi x D
h = ------------ Eqn. 3 2 x t
Where h = hoop stress
Pi = internal pressure
D = outside diameter
t = nominal or minimum wall thickness
Here, the hoop stress calculated should be below SMYS and stated in terms of percentage.
Minimum Burst Pressure, Pb The minimum burst pressure, Pb is determined by one of the following formula:
t
Pb = 0.90 x (y + t) (----------) for D/t ratio 15 Eqn.4
(D – t)
Where Pb = Minimum burst pressure
y = Specified minimum yield strength (SMYS)
t = Specified minimum ultimate tensile strength
t = Nominal wall thickness
D = Outside diameter
Hydrostatic Test Pressure The hydrostatic test pressure, Pt is given by:
Pt = Fd x J x T x Pb Eqn.5
Where Pt = Hydrostatic test pressure
Fd = 0.90, Internal pressure (burst) design factor
J = 1.0, Longitudinal weld joint factor
T = 1.0, Temperature de-rating factor
Pb = Minimum burst pressure
Design Pressure The design internal pressure, Pd is given by:
Pd = 0.80 x Pt Eqn.6
External Collapse Pressure In the presence of external pressure and in the absence of other loads, the buckling mode of an ideally
round and straight pipe depends on D/t ratio. For large D/t (thin wall pipe), the buckling occurs while
the material is still elastic (elastic buckling).
Pipeline Design 9
The elastic collapse pressure is calculated from the equation below:
2E t PE = --------------------- ( ------)3 Eqn.7
(1-2) D
Where D = Pipe outer Diameter
t = Wall thickness
E = Young’s Modulus
= Poisson’s ratio
PE = Elastic Collapse Pressure
The elastic collapse occurs first in thin wall pipeline except in pipelines with heavy wall thickness.
The pipelines most of the time, not perfectly circular, but always have some ovality. When these
pipelines subjected to external pressure, the ovality increases and become very large when the external
critical pressure limit is reached. Due to the increased internal pressure, the hoop stress and the
circumferential bending stress (plastic collapse pressure) reaches the yield point and at this time the
collapse occurs.
At small D/t ratio (Thick pipe) buckling results from yielding of the cross section. Yielding occurs at a
pressure Py given as
The plastic collapse pressure, Py , is found by the following equation
t
Py = 2 x y (-------------) Eqn.8 D
Where Py = External pressure at yielding
y = Specified Minimum Yield Strength (SMYS) in hoop direction
D = Outside diameter of the pipeline
t = Wall thickness
At intermediate values of D/t, the buckling regime transitions from elastic collapse PE to yield Py, with a
collapse pressure (Murphy)
2
E
2
y
Ey
PP
PPPc
Where PC = Collapse pressure Eqn.9
Generally, the collapse pressure is between the elastic critical pressure and plastic collapse pressures.
Corrosion Allowance While calculating the wall thickness, a corrosion allowance of 1/16 in may be added to the thickness
calculated.
10 Offshore Pipeline Systems
1.5 Design for Upheaval Buckling
Uplift or Upheaval There has been a rapid increase in the number of small-diameter pipelines transporting high pressure
and high temperature hydrocarbons. When a pipeline is buried and operated at higher than ambient
temperature, it will try to expand. If it is axially restrained, for example by the friction of the
surrounding soil, a compressive axial force is produced, leading to potential upheaval buckling. The
resulting pipeline response to such upheaval buckling might be unacceptable in terms of vertical
movement or excessive yielding of the material. The risk of upheaval buckling must be mitigated by
appropriate design of the pipeline backfill material.
The pipelines buried in very loose silty sand can experience very low levels of uplift resistance. The
Uplift Factors as low as 0.1 to 0.2 have been suggested. This has important implications for the
installation of buried pipelines in these types of soil conditions offshore.
The uplift behavior of buried offshore pipelines is governed by a combination of at least two
mechanisms: wedge failure and soil flow-around. The dominance of one mechanism over the other
depends on basic parameters such as the depth-to-diameter ratio and soil relative density.
This has been dealt with more fully in subsequent chapter –On Bottom Stability.
Figure A2
Typical Loading Characteristics on pipe in different water depth
Referring to the figure above (J-lay method) as long as the pipeline is vertically straight, and above the
water level, it will experience only the axial tension. As the pipeline moved down into the water, it
experiences axial tension and the external pressure due to water depth. We can see that there is no
bending movement as the pipeline is straight. When the pipeline approaches the seabed, it has to bend to
follow the catenary shape. At this section, the bending moment, axial tension and the external pressure
acting together. These combined forces induce a compressive stress, which is to be taken care of in wall
thickness calculations.
Buckling Initiation Buckling may be initiated at this stage due to combined stresses, particularly when the external pressure
exceeds the collapsible strength of the pipeline. As the pipeline is pushed through with the catenary
Pipeline Design 11
shape, bending forces also acts on the pipeline, which should not exceed the bending capacity of the
piping materials.
The buckle initiation pressure is given by the following equation:
064.2
biD
tE02.0P
Where, Pbi = Buckling Initiation Pressure (MPa)
E = Modulus of Elasticity (MPa)
D = Nominal diameter of the pipe, mm
T = Minimum wall thickness, mm
Buckle Propagation During the installation or during operation, if there is a chance of occurrence of a local buckling, it may
propagate along the pipeline. It means that the buckling propagation may occur if the external pressure
exceeds the propagation pressure for the pipeline. It is to be noted that the propagation of buckling is
defined as the flattening of large section of the pipeline due to external pressure alone.
The minimum propagation buckling pressure is calculated based on the following equation:
4.2
ybpD
t24P
Where, Pbp = Propagation Pressure, MPa
y = Specific Minimum Yield Strength, MPa
t = Minimum pipe wall thickness, mm
D = Nominal pipe diameter, mm
Buckle propagation can be prevented by increasing the wall thickness to the buckle propagation
thickness or by designing buckle arrestors spaced along the pipeline. The space between two buckle
arrestors is defined based on cost and risk optimization. If the pipe will be installed by the J-lay method
using a collar system, a hex joint may be the preferred spacing.
For deep water pipelines it is common to use buckle arrestors, because the thickness required against
buckle propagation is relatively high and will be too costly to use for the entire pipeline length. There
are various types of external and internal buckle arrestors, such as integral ring, welded ring, welded
sleeve, heavy-wall integral cylinder, and grouted free-ring buckle arrestors.
An important factor in the local buckling resistance is the dimensional tolerance of the pipeline, in
particular “Ovality”, which is a measure of out-of-roundness. The ovality of the pipeline is directly
linked to the collapse component of the local buckling criterion, and higher ovality will require
additional wall thickness for collapse resistance. In the opposite way, more stringent dimensional
tolerances may lead to a wall thickness reduction.
1.6 Design for Hydrodynamic Stability The pipelines after installation on the seabed are subjected to various forces acting on it to dislodge
them from its position. The stability is jeopardized by the following forces:
(a) Steady and Oscillatory water currents—Environmental Loading
(b) Wave Induced forces—Environmental Loading
(c) Other internal or external loads
Hydrodynamic stability is generally obtained by increasing the submerged weight of the pipe by
concrete coating.
12 Offshore Pipeline Systems
Hydrodynamic stability is also obtained by other means such as:
a) Increasing the wall thickness
b) Placing concrete blankets or bitumen mattresses across the pipeline,
c) Anchoring or covering it with sand, gravel or rock.
The Hydrodynamic forces may be reduced by placing the pipeline in a trench on the seabed, prior or
subsequent to installation. The natural backfilling of a pipeline depends on the environmental
conditions, such as wave and current and the seabed sediment at the location.
A pipeline on the seabed forms a structural unit where displacement in one area is resisted by bending
and tensile stresses. The pipeline self-lowering may result in some sections being embedded to a larger
degree than determined by touchdown forces and parts may even be fully buried. The embedment is
influenced by soil characteristics and phenomena such as scour, sediment transport and other seabed
instabilities. In some other sections, the pipe may be slightly elevated above the seabed due to seabed
undulations or scour processes. For both conditions, the hydrodynamic forces are reduced relative to the
idealized on bottom condition.
Therefore, it is important to evaluate the parameters of pipelines so that no lateral movements at all
permitted and alternatively, certain limited moments accepted, which will not interfere with the adjacent
objects or overstressing of the pipeline. These forces are further classified as:
a) Submerged weight of the pipe, W
b) Friction resistance forces, Fr
c) Drag forces, FD
d) Lift forces, FL
e) Inertia force, Fi
In order to arrive at the different design parameters with respect to the on-bottom stability, the above
mentioned forces along with the estimation of the submerged weight are performed at different water
depths. Various mathematical models were created by eminent researchers and arrive at a modeling
diagram of these forces acting on the pipe cross-section. This is shown in the figure below.
Figure A3
Hydrpdynamic Stability of pipe
Where FD = Drag force, (N/m)
Fi = inertia force, (N/m)
FL = Lift force, (N/m)
W = Total submerged weight of pipe, including concrete coating
and wrap, steel pipe, and contents , (N/m)
N = Normal force, (N/m)
Fr = friction resistance
V = Flow velocity in boundary layer m/sec.
θ = Slope of seabed
Pipeline Design 13
Equilibrium of Forces The Equilibrium condition in the vertical direction is not always considered, unless the expected
penetration of a pipeline on a very soft seabed. Therefore, it is restricted to examine the equilibrium
condition in the horizontal direction only.
Forces Acting on Offshore Pipelines with Inclined Sea Bed The pipeline remains stable on the seabed, summation of all forces on the pipe must satisfy the static
equilibrium equation given by:
Horizontal forces (X) = FD + Fi – Fr – Wsin θ = 0 (1)
Vertical forces (Y) = N + FL – W cos θ = 0 (2)
If pipe is resting on the seabed with little embedment into the soil, then the lateral frictional resisting
force (Fr) can be related to the normal force (N) by:
Fr = μ N (3)
Where μ = Lateral friction coefficient between pipe surface and the seabed.
μ = 0.5 to 0.9 depending on the coating and the type of soil.
Combining equations 1 and 2 and using equation 3 yields:
FD + Fi + μ (FL - W cos θ) = W sin θ (4)
The minimum pipe submerged weight (W) can be determined using equation (4)
sincos
FFFW LiD (5)
Forces Acting on Offshore Pipelines with Horizontal Sea Bed The minimum submerged weight required to prevent any horizontal movement of the pipeline under the
extreme environmental loading, is calculated by a single static force balance of the horizontal
hydrodynamic and soil frictional forces. The stability criteria may be expressed as based on DNV RP
E305
Where, WSUB = Submerged weight of pipeline, (N/m)
FD = Hydrodynamic Drag force per unit length, (N/m)
Fi = Hydrodynamic Inertia force per unit length, (N/m)
FL = Hydrodynamic Lift force per unit length, (N/m)
Fw = Calibration factor from CI 5.3.7 DNV RP E305
= Coefficient of friction between pipe and soil from
CI 5.3.3 DNV RP E305
14 Offshore Pipeline Systems
Pipeline Submerged weight consists of:
(1) Steel
(2) Internal corrosion liner (If applicable)
(3) Corrosion coating (If applicable)
(4) Insulation coating (If applicable)
(5) Concrete coating (If applicable)
(6) Marine growth (If applicable)
(7) Internal contents
(8) Metal loss through internal/external corrosion
Figure A4
Pipeline cross-section
The Hydrodynamic Diameter of the pipe is given by:
Dhyd = DST + 2(tcc + t ic + t c + tmg)
The weight of each component is calculated per unit length by the
Ring area x =Thickness x density and add to this corrosion allowance usage factor
Pipeline’s Buoyancy, submerged weight, and specific gravity is calculated as follows:
(a) Pipeline Buoyancy B = /4 OD2 SW
(b) Pipeline submerged weight WS = W – B
(c) Pipeline specific gravity = W/B = WS/B + 1
For steady flow conditions:
The Hydrodynamic Drag forces acting on pipeline with diameter D are
(6)
The Hydrodynamic Inertia forces, Fi
(7)
Pipeline Design 15
The Hydrodynamic Lift forces FL
(8)
Where D = Pipe outside diameter
Ue = Effective horizontal water- particle velocity over pipe height
du = Horizontal water- particle acceleration over pipe
CD = Hydrodynamic drag coefficient (Generally taken as 0.7)
Ci = Hydrodynamic inertia coefficient (Generally taken as 3.29)
CL = Hydrodynamic lift coefficient, (Generally taken as 0.9)
NOTE:
In conventional on-bed plain pipeline stability calculations, the values CD = 0.7, CL=0.9 and Ci=3.29 are
widely employed
Recommended coefficients for pipe design are show in Table below
Table A1
Recommended coefficients for pipe design (Exposed pipe)
Horizontal water particle velocity U can be calculated as
In shallow water where, d/L 0.04
In transitional water where, 0.04 d/L 0.5
In this work the values of d / L varied between 0.150 and 0.235,
Where d = water depth,m
L =wave length, m
, the velocity is maximum
where t = 0
16 Offshore Pipeline Systems
The following term vanishes at t = 0
Consequently, the value of Fi is equal 0
(9)
Where
T = wave period
t = time
y = is a height from sea floor in the boundary layer
The maximum horizontal water particle velocity U occurred at t = 0 then cos θ =1
1.7 Design for Operating Stress and Strain The pipeline design based on operating stresses and end movements or expansion is considered here.
During the operating stage of the pipeline flow, there is pressure and temperature inside the pipeline.
The resultant forces due to the pressure and the difference between temperature inside the pipeline and
the surrounding fluid, forces are created, which are to be contained within the tolerances, and the
pipelines tend to expand rapidly and longitudinally.
Generally, the pipelines are considered as pressure vessels in cylindrical form. The pipes are also
classified as:
a) Thin-wall pipe, where D/t ratio greater than 20
b) Thick-wall pipe, where D/t ratio less than 20
Figure A5
Thin-wall pipe
Pipeline Design 17
Thin-Wall Pipe According to Pascal’s law, the pressure acting in confined space is equally in all directions, throughout
the space with equal magnitude, undiminished.
Based on this theory, the internal pressure “p” is acting in equal magnitude and distributed around the
circumference will produce a circumferential stress, called “Hoop’s Stress” and the value given as:
Where, h = Hoop Stress
P = Net internal pressure
D = Internal diameter
t = Wall thickness
The longitudinal stress “L” is calculated by dividing the total pressure force against the end of the pipe
by the cross-section area of the pipe. This is represented by the following equation:
Where, L = Longitudinal Stress
P = Net internal pressure
D = Internal diameter
t = Wall thickness
The Strain in the pipeline is calculated based on the Modulus of Elasticity of the pipeline material.
Stress
Modulus of Elasticity E = -----------------
Strain
Therefore:
The circumferental strain E
hh
The longitudinal strain E
LL
For the pipelines in deep water, there are external pressure are also acting on the outside surface of the
pipe. In this case, D is taken as the nominal outside diameter and the hoop stress must be calculated
based on ANSI/ASME B31.8, B31.4 design practices.
Thick-Wall Pipe If the D/t ratio is less than 20, we have to use the thick-wall equations for Hoop and Radial stresses. The
major difference between the thin- and thick-wall formulations is that for thick wall conditions, the
variation in stress between inner and outer surface becomes significant. The cross-section for a thick
cylinder and its representative stresses are shown in the figure below.
18 Offshore Pipeline Systems
The radial stresses for internal pressure shown in the following equation:
2
2
22
2
rr
a1
ba
pb and
2
2
22
2
hr
a1
ba
pb
Where, r varies from b to a, which are the inside and outside radii, respectively
Both r and h have maximum at r = b
The Longitudinal stress L , is given by
22
2
Lba
pb
Figure A6
Thick-wall pipe
For the calculation of burst pressure, take one half of the algebraic difference between the maximum
and minimum principal stresses at any point. Since the longitudinal stress is neither the maximum nor
the minimum value,
2
rh
Based on the radial stress formulae shown earlier, the longitudinal stress becomes
222
22
bar
pba
Pipeline Design 19
For the internal pressure only, the shear stress is a maximum on the inner surface. Therefore,
22
2
maxba
pa
Thermal Expansion Stresses Between pipeline installation and at the operating conditions, there is a temperature gradient exists. The
thermal stress and the longitudinal strains are calculated based on pipeline installation conditions, such
as:
a) Unrestrained
b) Restrained
The longitudinal strain is proportional to the magnitude of the temperature difference.
In unrestrained uniaxial condition, the longitudinal thermal stress is zero, but the thermal strain exists
and is given by the following equation:
t = t x T
Where t = Thermal strain
t = Coefficient of thermal expansion
T = The temperature change T2 – T1
In restrained condition, the longitudinal strain is zero, but the compressive stress generated by the
restrained expansion. It is to be noted that the thermal stress caused by a temperature gradient normally
does not produce any gross distortion. However a high stress can be generated. The magnitude of the
thermal stress can be roughly estimated by the following equation:
= - E t T
Where, = Thermal stress,
E = Modulus of Elasticity
t = Coefficient of thermal expansion,
T = (T2 – T1) Temperature difference,
The negative sign indicates that the thermal stress for a positive temperature increase in restrained
condition is compressive. A positive sign indicates that the thermal stress for a temperature decrease in
restrained condition is tensile.
When temperature in a pipeline reaches T2 from T1, the pipe section of length L will expand at rate of:
t (T2 –T1) L.
But the hoop tensile stress will make it to shrink at the rate of:
Sh L / E
20 Offshore Pipeline Systems
This shrinkage due to hoop tension is similar to stretching a rubber band. The rubber band when
stretched in the longitudinal direction, the sidewise dimension will shrink. In steel pipe, if it is stretched
one inch in one direction, it will shrink 0.3 inch each in both perpendicular directions. This 0.3 is called
the Poisson’s ratio and the shrinkage is known as “Poisson Shrinkage”. After deducting this Poisson
shrinkage from the expansion, we will get the net expansion as:
= [t (T2 –T1) L] – [ Sh L / E]
The longitudinal stress produced is equivalent to the stress required to squeeze net expansion , back to
the original position. Since SL = - E / L, then
SL = - E t (T2 –T1) + Sh
The combined equivalent stress shall not exceed 90% of pipe SMYS. The figure below shows stresses
acting on the pipe wall. For the biaxial stresses shown, the code uses maximum shear theory of failure
which says that pipe yields when maximum shear reaches shear yield stress. The maximum shear stress
max in this case can be easily shown as:
Where, = Shear stress in the principle axis of the pipe,
Sh = Hoop stress
SL = Longitudinal stress
Figure A7
Stress characteristics on pipe
Since the yield stress equals 0.5 times the tensile yield stress, an equivalent tensile stress defined as 2 x
maximum shear stress is used to compare with tensile yield stress. The equivalent tensile stress is
therefore equal to:
Se is to be limited to 0.9 x SMYS. The correct sign should be used for SL in substituting in the above
equation. In cases where direct shear stress is negligible, the absolute sum of hoop stress and
compressive longitudinal stress should not exceed the 0.9 x SMYS limit.
Pipeline Design 21
Thermal Bowing Effect For thermal stresses, we are concerned mainly with the high-temperature areas. These are the areas that
can create high enough thermal stresses to cause cracks in the pipelines. However in some systems,
even though the temperature is not hig, another thermal effect may create a different kind of problem.
This is the lesser-known “Bowing Effect”.
Figure A8
Thermal bowing effect
For example, assume we have a 16-in gas line that is not insulated and operates at 200F. During a
summer shower, the pipe’s top may suddendly quench to 100F, while the bottom maintains 200F.
This 100F quench on the top produces a shrinkage of 0.00065 in/in of pipe surface. This shrinkage will
bend the pipe into an arc with a radius of curvature equal to R= 16 / 0.00065 = 24,615 in. This bowing
effect, as shown in figure above can potentially lift the ends of a 100-ft long pipe up 7-in. Although the
actual lift will be greatly reduced by the pipe’s weight, its significance cannot be ignored.
The damage caused by thermal bowing is often very ghostly. It normally happens without anybody
actually seeing it. In the above example, when there is a rain on the surface of the pipe, the ends move
up and possibly tear off some supports or small connections. However, when the rain stops or when the
temperature even out, the pipe returns innocently to its initial position. It leaves the damage without
giving any clue of the cause.
1.8 Pipeline Spanning and Control
In offshore oil and gas transportation, miles and miles of pipelines are laid every year, in the seabed.
Due to the uneven of seabed and the scouring of ocean currents, pipeline span is the basic component in
the pipelines.
The pipeline spanning occurs when the contact between the pipeline and the seabed is lost over an
appreciable distance on a rough seabed. If the actual span lengths exceed the allowable length, it should
be reduced to avoid pipeline damage.
The pipeline span may be damaged by the interaction of wave and ocean currents, if the span is long
enough. Moreover, due to the ocean current, periodic vortex may occur and it may result in the periodic
vortex-induced vibration of the pipeline span.
Vibration amplitude of pipeline span becomes very large when resonance occurs, and then the vibrating
stress range may far exceed the fatigue limit of pipeline material. Thus severe fatigue damage will be
induced to the pipeline span. Therefore, the static and dynamic analysis of the pipeline span is an
important topic for the security of the offshore pipeline system.
22 Offshore Pipeline Systems
Figure A9
Pipeline spanning
In static analysis, the effects of the internal flow velocity and seabed stiffness on the pipeline’s lateral
deformation and bending stress are studied.
In dynamic analysis, the preliminary relationships between the internal flow velocity and the foundation
stiffness to the natural frequency of the pipeline span are investigated.
It is found that the lateral deformation increases with the increment of internal flow velocity, but
decreases with the increment of seabed stiffness. The bending stress at the ends of span increases with
the increment of internal fluid velocity and the seabed stiffness, however the stress at the middle of the
span shows the converse tendency. Moreover, increasing the seabed stiffness or decreasing the internal
fluid velocity can lead to higher natural frequency.
The pipeline in the direction of wave and current is cosidered as a cylinderical object. The flow of wave
and a current around a pipeline span can result in the generation of sheet vortices in the wake.These
vortices are shed alternatively from top to bottom of the pipeline resulting in an oscillatory force exerted
on the span.
Pipeline Design 23
Figure A10
Vortex Regimes of fluid flow across smooth circular cylinders
Free Span Offshore pipelines are laid on the seabed by different methods in different shapes either embedded in a
trench (buried) or laid over the uneven seabed (unburied). Since buried pipeline laying is more costly,
the unburied pipelines becomes common, but not without any problem, like “Free Span”.
Free span occurs because of three reasons, namely:
a) Unsupported weight of the pipeline section.
b) Unevenness in the seabed-exists because seabed is not entirely flat.
c) Scouring phenomena- occurs near the pipeline because of the variation on the flow
regime around the pipeline which makes a severe sediment transport under the
pipeline.
As shown in the figures above, when a fluid flow across a pipeline, the flow separates, vortices are shed,
and a periodic wake is formed in the downstream of the flow. Each time this happens, it alters the local
pressure distribution and the pipeline experiences a time varying force at the frequency of vortex
shedding. The Resonance and fatigue are the two crucial problems for the pipes laid on free span, which
must be limited by the designer to increase pipe safety. The resonance occurs when the ambient vortex
shedding frequency around the pipe becomes equal to the pipe natural frequency and as a result fatigue
is developed.
As shown in figure, laying the pipe between two shoulders in seabed is inevitable.
24 Offshore Pipeline Systems
Figure A11
Free span
Strouhal Number The Strouhal Number is a dimensionless value useful for analyzing oscillating unsteady fluid flow
dynamics problems.
The Strouhal Number can be expressed as
St = f D / V
Where St = Strouhal number
f = Vortex shedding frequency
D = Diameter of the pipeline
V = Velocity of flow current.
The Strouhal Number can be important when analyzing unsteady, oscillating flow problems. The
Strouhal Number represents a measure of the ratio of inertial forces due to the unsteadiness of the flow
or local acceleration to the inertial forces due to changes in velocity from one point to another in the
flow field.
The vortices observed behind a stone in a river, or measured behind the obstruction in a vortex flow
meter, illustrates these principles.
Vortex Shedding Frequency
Figure A12
Vortex Shedding Frequency
Pipeline Design 25
The vortex-shedding frequency is the frequency at which pairs of vortices are shed from the pipeline
and is calculated as follows:
D
VSf t
Where f = vortex shedding frequency (Hz)
St = Strouhal number (dimensionless)
V = flow velocity (m/s)
D = Pipe diameter
Natural Frequency The natural frequency of the pipeline span depends on:
(a) Pipe stiffness= Modulus of elasticity of pipe material x Moment of Inertia of pipe
E xI = /64(D4 – d
4)
(b) End conditions of the pipe span =End condition constant
=9.87 for pinned-pinned
= 15.5 for Clamped-pinned
= 22.2 for Clamped-clamped
(c) Length of span, Ls in meters
(d) Effective mass of the pipe= Sum of total unit mass of the pipe, the unit mass of pipe contents, and
the unit mass of the displaced water.
= Me = Mp + Mc + Ma in kg/m, here Ma = /4 x D2 x
The formula given is
4
se
en
LM
E
2
Cf
Critical Span Length Under resonant conditions, sustained oscillations can be excited and the pipe line will oscillate at a
frequency. This oscillation result in catastrophic failure of the pipeline.
These oscillations are classified into two categories, depending on the current velocity and pipe span
length.
a) Inline oscillations
b) Cross-flow oscillations.
The critical span length or the unsupported pipeline length at which oscillations of the pipeline occur for
a specific current is based on the relationship between the natural frequency of the pipe free span and
the reduced velocity.
26 Offshore Pipeline Systems
The critical span length for in-line oscillation is expressed as:
e
nec
M
E
2
fCL
The critical span length for cross-flow oscillation is expressed as:
ec
rec
M
E
V2
DVCL
Where, LC = Critical Span Length, m
Ce = End condition constant
fn = Natural frequency, Hz
D = Diameter of pipe, m
Vr = Reduced velocity, m/s
VC = Current velocity, based on 100 years average, m/s
E = Modulus of elasticity of pipe material, 200 x 109 N/m
2
I = Moment of Inertia of pipe,
Me = Effective mass of pipeline, kg
10 Step Design Of Pipeline Free Span Length
1) Determine the design current (100 year near bottom perpendicular to the pipe)
2) Calculate the effective mass of the pipeline
3) Calculate the Reynolds number
4) Calculate the stability parameter
5) Using the stability parameter, calculate the reduced velocity for in-line motion
6) Using the Reynolds number, calculate the reduced velocity for cross-flow motion
7) Calculate the end condition constant
8) Calculate the critical span length for in-line and cross-flow motion
9) Select either critical span length for in-line or cross-flow motion
10) Calculate Fatigue life for in-line or cross-flow motion.
1.9 Design of Pipeline Risers
Definition of Riser
A Riser is defined as the vertical or near-vertical pipeline connecting the facilities above water to the
subsea pipelines.
Figure A13
Riser pipe design
Pipeline Design 27
The Risers are classified in many ways, based on the applications. These are:
(a) Steel Catenary Risers
Conventional SCR
Weighted SCR
Pipe-in-pipe SCR
Concentric SCR with gas lift
Threaded SCR
Lazy-wave risers
(b) Top-Tensioned Risers
Dry tree production
Drilling riser systems for Spar,
TLP, Barge and deep draft production vessels.
(c) Freestanding / Hybrid risers
The Single Line Offset Riser (SLOR)
Concentric Offset Riser (COR)
Single-leg hybrid risers
(d) Drilling Risers
Conventional shallow and deep water MODU operations,
High pressure SBOP systems
Fixed platform drilling
(e) Completion and Work-over Risers
Mono bore,
Dual and triple bore risers, using union nut, tool joint and casing connection systems
(f) Flexible Risers
Deep and shallow water riser
Flow line systems
(g) Rigid Jumpers
Interface between more substantial subsea structures (risers/flow lines) and are required to
accommodate significant static and dynamic loads
(h) Umbilical
Both shallow water and deep water applications.
Though there are many types and classification according to field condition, we deal in this chapter with
a simple steel catenary Riser system or simply, we may call it as “Conventional Steel Risers”.
Recommendations for initial pipe sizing of these systems generally follows that used for flow line and
pipeline systems covering burst, collapse and buckling criteria. However, due to the dynamic nature of
these systems, wall thickness increases are often required, to increase the weight in water, to achieve an
acceptable response. This is particularly the case for harsh environments and where significant vessel
motions are expected.
There are three principle steel catenary riser configurations:
28 Offshore Pipeline Systems
STEEL CATENARY RISER (SCR)
Figure A14
Steel Catenary Riser
WAVE CATENARY RISER (WCR).
Figure A15
Wave Catenary Riser
Pipeline Design 29
HYBRID RISERS
Figure A16
Hybrid Riser
The former is used for TLPs (Tension Leg Platforms) and Spars where motions are small or for other
vessel types where the environment is very mild. The WCR is proposed for catenary moored vessels
such as FPSO and may be configured even for environments. Hybrid Risers are used with FPSO, Barge
and Semi.
The riser length may be estimated using simple geometric considerations.
Simple Catenary Riser
Total Riser Length = ((Water Depth – MBRxA)/Cos) + (0.5xxMBRxA)
Wave Catenary Riser
Total Riser Length = ((Water Depth – MBRxA)/Cos) + (2.5xxMBRxA)
Start of Riser Buoyancy = ((Water Depth-MBRxA)/ Cos) + (xMBRxA)
Buoyancy Length = (xMBRxA/2)
Buoyancy Upthrust = 2x(Pipe + Contents Weight )
Where A = Factor 1.0 for mild environments
= Factor 1.2 for severe environments
= Riser top angle to vertical, typically between 10 to 20 degrees depending on
severity of environment and water depth.
MBR = Minimum Bend Radius based on 80% material yield strength (Typically API
grade X65-N80)
Minimum Elastic bend Radius is given by R=ED/2Sa
Where E = Youngs modulus of Elasticity
D = Diameter of pipe
Sa = Longitudinal Stress allowed for bending
30 Offshore Pipeline Systems
Additional pipe length of 750m should be included in both cases to allow for Touch Down Point (TDP)
movement between near and far offset conditions.
A = A factor between 1.0 (mild) and 1.2 (Severe) depending on severity of
environment
0 = Riser top angle to vertical, typically between 10 and 20 degrees depending on
severity of environment and water depth.
MBR is minimum bend radius based on 80% material yield strength (typically API
grade X65-N80)
An additional pipe length of approximately 750 m should be included in both cases
to allow for TDP movement between near and far offset conditions.
Riser Design The risers are designed to meet the following design requirements. The methods of the analyses are
described in the following subsections.
Vortex Induced Vibration
Equivalent Stress
Vortex Induced Vibration Allowable span lengths for the vortex induced vibration criteria are calculated based on riser general
arrangement drawings and DNV 1981, whereby the reduced velocity is defined as:
Where, Vr =Reduced Velocity
V = Flow velocity normal to pipeline (mm/sec)
fn = Pipeline natural frequency (Hz)
Do = Pipeline outside diameter (mm)
Another parameter controlling the dynamic vibration is the stability parameter (KS) defined as:
Where KS = Stability parameter
Me =Effective mass per unit length (kg/m)
(includes mass of pipe, content and added mass
=Logarithmic decrement of structural damping, 2dr
dr = Damping ratio, 0.02 for steel in water
=Mass density of surrounding water (kg/m3)
D = Pipe diameter (m)
Based on the calculated stability parameter, the limiting reduced velocity can be obtained from Figure
A.3 of DNV 1981. As per DNV 1981, the in-line oscillation of a free span is initiated at lower velocities
than those required for the onset of cross flow motion. Therefore, the maximum allowable span length
for the in-line motion criterion will automatically satisfy the cross-flow criterion. The equation for
reduced velocity (Vr) can be re-arranged as follows:
The natural frequency is given by fn
Pipeline Design 31
Combining the two equations and solving for L:
The vortex shedding analysis is performed using in-house spreadsheet files. The spreadsheet calculates
the allowable riser span length to avoid the onset of pipeline in-line and cross flow oscillations induced
by vortex induced vibration, which complies with the DNV 1981 method. Based on the calculated span
length, the riser clamp elevation is then identified such that the clamp elevation spacing is always lower
than the riser maximum span length.
Steady current and wave velocity are considered in the riser vortex vibration analysis
Riser analysis have been analyzed using AUTOPIPE software
Definitions of Design Loads Loads acting on risers can be divided into environmental, functional and accidental loads.
Environmental Loads Environmental loads are defined as loads imposed directly or indirectly by environmental phenomena
such as waves, current, wind, ice and snow. In general, the environmental loads vary with time and
include both static and dynamic components. The characteristic parameters defining environmental
loads are to be appropriate to the operational phases, such as transportation, storage, installation, testing
and operation.
Functional Loads Functional loads are defined by dead, live and deformation loads occurring during transportation,
storage, installation, testing and operation.
Dead loads are loads due to the weight in air of principal structures (e.g., pipes,
coating, anodes, etc.), fixed/attached parts and loads due to external hydrostatic
pressure and buoyancy calculated on the basis of the still water level.
Live loads are loads that may change during operation, excluding environmental
loads which are categorized separately. Live loads will typically be loads due to the
flow, weight, pressure and temperature of containment and fluid absorption.
Deformation loads are loads due to deformations imposed on risers through
boundary conditions such as reel, stinger, rock berms, tie-ins, seabed contours,
constraints from floating installations, etc.
The functional loads are to be determined for each specific operation expected to occur during the
riser’s life cycle and are to include the dynamic effects of such loads, as necessary. In addition, extreme
values of temperatures expressed in terms of recurrence periods and associated highest and lowest
values are to be used in the evaluation of pipe materials.
Accidental Loads Accidental loads are defined as loads that occur accidentally due to abnormal operating conditions,
technical failure and human error. Examples are soil-sliding, earthquakes, mooring failure and impacts
32 Offshore Pipeline Systems
from dropped objects, trawl board or collision. It is normally not necessary to combine these loads with
other environmental loads unless site-specific conditions indicate such requirement.
Dynamic effects are to be properly considered when applying accidental loads to the design. Risk based
analysis and past experience may be used to identify the frequency and magnitude of accidental loads.
Risers are to be adequately designed to avoid collisions with floating installations or from other risers.
The riser is to have adequate strength to withstand impact loads caused by small dropped objects,
floating debris or ice, where applicable.
Table A2
Categorization of Design Loads for Risers
Pipeline Design 33
Figure A17
Riser design flow chart
34 Offshore Pipeline Systems
(A) Wind Loads The wind loads are acting upon the parts of risers that are above the water surface and marine structures
to which the risers are attached.
For winds normal to the riser axis, the following formula is used to calculate the wind load.
FW = 0.5 x ρa x Cs x VY
2 x A
Where FW = Wind Load
a = Density of air
CS = Shape coefficient (dimensionless, = 0.50 for cylindrical section)
VY = Wind speed at altitude Y
A = Projected area of the pipe on a plane normal to the direction of wind
(B) Hydrodynamic Forces Hydrodynamic forces consist of (a) Drag force (b) Inertia force
(a) Drag Force
The drag force for a stationary pipe is given by
FD = 0.5 x ρ x OD x CD x Un x |Un|
Where, FD = Drag Force
= Density of water
OD = Total external diameter of pipe, including coating, etc.
CD = Drag coefficient (dimensionless)
Un = Component of the total fluid velocity vector normal to the axis of pipes
(b) Inertia Force
The inertia force for a stationary pipe is given by
Fi = ρ x (π/4 x OD
2) x CM x an
Where Fi = Inertia Force
= Density of water
OD = Total external diameter of pipe, including coating, etc.
CM = Inertia coefficient based on the displaced mass of fluid per unit length
an = Component of the total fluid acceleration vector normal to the axis of the pipe
Therefore, the hydrodynamic force
F = FD + Fi
Where F = Hydrodynamic force per unit length of pipes
FD = Hydrodynamic Drag force per unit length
Fi = Hydrodynamic Inertia force per unit length
Pipeline Design 35
Lift Force The lift force for a stationary pipe located on or close to the seabed is given by
FL = CL x 0.5 x ρ x Un
2 x AL
Where FL = Lift force per unit length
CL = Lift coefficient
AL = Projected are per unit length in a plane normal to the direction of force
For risers that exhibit substantial rigid body oscillations due to the wave action, the modified form of
Morison’s equation may be used to determine the hydrodynamic force.
nnm
2
n
2
nnnnDCD áaC4
OD
g
ca
4
ODúuúuCOD
2
1FFF
Where ún = Component of the velocity vector of riser normal to its axis
Cm = Added mass coefficient, CM – 1
án = Component of the acceleration vector of riser normal to its axis
The values of un and an are to be determined using recognized wave theory appropriate to the wave
heights, wave periods and water depth at the installation location, as well as the elevation at which the
load is calculated.
Burst Pressure The specified minimum burst pressure for risers can be calculated as follows:
Where Pb = Specified minimum burst pressure
D = Steel nominal outside diameter of pipe
T = Wall thickness
SMYS = Specified Minimum Yield Strength at design temperature
SMTS = Specified Minimum Tensile strength at design temperature
Hoop Stress Criteria The wall thickness of riser pipe is to be designed, mainly based on the internal pressure containment. In
selecting the wall thickness, consideration given to pipe’s structural integrity, stability during
installation, system pressure test and operation, local buckling collapse, global buckling, on-bottom
stability, protection against impact loads, high temperature and uneven seabed induced loads etc.
Hoop Stress The hoop stress h for pipes is to be determined by:
Where, h = Hoop stress
Pi = Internal design pressure
Pe = External design pressure
D = Steel pipe nominal outside diameter
t = Nominal pipe wall thickness
36 Offshore Pipeline Systems
Maximum Allowable Hoop Stress
h = x SMYS x kT
Where, h = Maximum allowable hoop stress,
=Usage factor
= 0.72 oil risers
= 0.60 for gas risers connected to unmanned platforms
= 0.50 for gas risers connected to manned platforms
kT = Temperature dependent material strength de-rating factor-ASME B31.8
SMYS = Specified minimum yield strength of material
Longitudinal Stress The Riser pipes are designed against longitudinal forces and the longitudinal stress is designed based on
the following equation:
t x SMYS x kT
Where, t = Longitudinal stress
= 0.80, usage factor
SMYS = Specified Minimum Yield Strength of the material
KT = Temperature dependent material strength de-rating factor-ASME B31.8
Von Mises Stress The Von Mises stress at any point in the pipe is to satisfy the following, which follows API RP 2RD.
Where, e = Von Mises Stress
r = Radial Normal Stress
h = Hoop Stress ( Normal stress circumference direction)
L = Longitudinal Normal stress
= Usage factor, Von Mises Stress
= 0.67 for design operation condition
= 0.80 for Design Extreme Condition or temporary condition
= 0.90 for Test condition
SMYS = Specified Minimum Yield Strength of material
The Von Mises axial stress is calculated by:
a = Di Mb/2I + Ta/As
Where, Di = Riser inside diameter
Mb = Bending Moment
I = Moment of Inertia
Ta = Axial Force
As = Steel Cross-sectional area.
Pipeline Design 37
Collapse Under External Pressure For risers installed at water depth up to 1500 m (5000 ft), the plastic collapse pressure formula in API
Bulletin 5C3 is to be used to calculate the required riser wall thickness.
For risers installed at water depth 1500 m (5000 ft) or more, the characteristic buckling pressure can be
calculated based on the following formulas.
Where,
2E t PE = --------------------- ( ------)3
(1-2) D
Where D = Pipe outer Diameter
t = Wall thickness
E = Young’s Modulus
= Poisson’s ratio
PE = Elastic Collapse Pressure
The plastic collapse pressure, Py , is found by the following equation
t
Py = 2 x y (-------------) D
Where Py = External pressure at yielding
y = Specified Minimum Yield Strength (SMYS) in hoop direction
D = Outside diameter of the pipeline
t = Wall thickness
The riser is not considered to collapse only, if the minimum differential pressure on the pipe satisfies the
following:
Pe – Pi b PC
Where, Pe = External pressure
Pi = Internal pressure, should be taken as atmospheric pressure.
b = Buckling design factor
= 0.7 for seamless or ERW pipe
= 0.6 for cold expanded pipe
PC = Collapse pressure
Buckling Propagation In many cases, it is found that during installation or shutdown of risers, local buckling or collapse may
start propagating along the pipe with extreme speed by the hydrostatic pressure of the seawater. Due to
this reason, the buckle arrestors are used to stop such propagating to confine the buckling/collapse
failure between arrestors. Buckling arrestors are normally be spaced at suitable intervals along the riser
for water depths where the extreme pressure exceeds the propagating pressure level.
38 Offshore Pipeline Systems
Buckling arrestors are used when:
Pe – Pi 0.72 x Ppr
Where, Ppr = Buckling propagation pressure
= 6 x SMYS x (2 t /D)2.5
It is preferable to design the arrestors based on API RP 1111
Fatigue Damage Failure Of Metallic Risers The Risers may be subjected to fatigue damage throughout their entire life cycle. The main reasons are
due to :
(a) Installation
(b) Startup and Shutdown cycles
(c) Wave and Current conditions
1.10 Pipeline Survey, Mapping and Routing
A very integrated part of infrastructure planning is to decide pipeline route (which has to be laid). To
come up with the system modeling for feeder pipeline and networking it is essential to carry out an
actual route survey. Various route surveys are done to come up with the best route selection.
The pipeline route selection is based on the following principles.
Distance of the pipeline route
Approachability for transportation of material and equipment for construction &
future maintenance of the pipeline
Consideration for selecting a route in the existing corridors.
Feasibility of pipe bending and limitations of topography & terrain of the route,
horizontal & vertical inclinations in pipelines.
As far as possible the crow line shall be a straight line and the shortest route
avoiding number of bends.
Avoid tidal wave region & preferably on safer side of highway/railway
Avoiding habituated areas, public utilities etc.
Avoiding unstable ground features
Minimize major crossing of rivers, roads, railways, streams, canals & power
transmission lines
Avoiding reserved Forest/ Sanctuary etc
Avoiding areas reserved for planned development including strategic/ defence
establishment
Ease of construction
Ease of obtaining ROU
Petroleum industries manage a wide range of information across all areas of their varied business
portfolios. A geographical information systems (GIS) is an integrating technology that can help meet
this challenge and leads to improved communication, greater efficiency, and better decision making.
Making decision based on geography is inherent to the oil business. Where to drill a well, route a
pipeline, build a refinery, and reclaim a site are all questions that rely heavily on an understanding of
geography to make intelligent business decisions
GIS is an integrating technology used to organize, analyze, and distribute data for day-to-day operations
as well as in research, engineering, and facility management
Pipeline Design 39
Geospatial Technology, commonly known as geomatics, refers to technology used for visualization,
measurement, and analysis of features or phenomena that occur on the earth. This terminology has
become common in the United States, and is synonymous with Spatial Information Technology.
Geospatial technology includes three different technologies that are all related to mapping features on
the surface of the earth. These three technology systems are GPS (global positioning systems), GIS
(geographical information systems), and RS (remote sensing).
A geographic information system (GIS), geographical information system, or geospatial
information system is a system that captures, stores, analyzes, manages and presents data with
reference to geographic location data. In the simplest terms, GIS is the merging of cartography,
statistical analysis and database technology. GIS may be used in archaeology, geography, cartography,
remote sensing, land surveying, public utility management, natural resource management, precision
agriculture, photogrammetry, urban planning, emergency management, landscape architecture,
navigation, aerial video and localized search engines.
Surveying or land surveying is the technique and science of accurately determining the terrestrial or
three-dimensional position of points and the distances and angles between them. These points are
usually on the surface of the Earth, and they are often used to establish land maps and boundaries for
ownership or governmental purposes. To accomplish their objective, surveyors use elements of
geometry, engineering, trigonometry, mathematics, physics, and law.
Remote sensing is the small- or large-scale acquisition of information of an object or phenomenon, by
the use of either recording or real-time sensing device(s) that are wireless, or not in physical or intimate
contact with the object (such as by way of aircraft, spacecraft, satellite, buoy, or ship). In practice,
remote sensing is the stand-off collection through the use of a variety of devices for gathering
information on a given object or area
Pipeline Routing Pipeline route design using GIS which include optimal routing for pipeline, selection of best route for
expansion pipeline and gas pipeline route selection using high resolution remote sensing images.
Data Aquisition Maps and field work are required for pipeline routing, pipeline design and construction. For this route,
topographic maps at a scale of 1:25000 were used.
Pipeline Routing Criteria The factors influencing pipeline route selection are technical and engineering requirements,
environmental considerations and population density. However, these factors are chosen to balance
engineering and construction costs against environmental costs and future liability. The engineering and
technical considerations used in this research include pipeline length, topography, surface geology, river
and wetland crossings, road and railroad crossings and the proximity to large population centers. High
relief terrain would result in higher construction costs and increase the need for pump stations.
Cost factors used in the least cost path analysis were calculated from existing pipeline and its
normalized baseline cost. Using cost of an existing pipeline project, percentages over the baseline costs
were calculated for construction in rock, clearing of brush and tree, crossing of rivers, railroads, and
passing through agricultural land and wetlands. Estimates were made of the slope ranges that are
associated with four terrain categories including flat, rolling, sharp choppy and rough that are
commonly used by pipeline estimators.
The topographic, geologic and land use data were used to develop a least cost pathway for pipeline
placement. The least cost analysis was performed by assigning cost factors associated with the crossing
of slopes, streams, wetlands, roads, railroads, rock, agricultural land, urban and industrial areas;
developing a cumulative cost surface; and then calculating a path of least resistance across that surface.
The locations of stream, road, and railroad crossings were digitized from the topographic map. The
40 Offshore Pipeline Systems
areas where rock was likely to be encountered were defined from the geologic map. A landuse map,
used to identify agricultural land and urban areas. Pipeline construction costs associated with terrain
conditions, geology and landuse were calculated from actual pipeline construction projects.
Pipeline Systems Primary Function
Product Transport
o Liquid hydrocarbons
o Natural gas
o Natural gas liquids
o Water
o Chemicals
Key Elements
o Product type
o Delivery rate
o Operating pressure
o Distance from field development to market
o Current and future demand/capacity
Pipeline Transportation Systems
Flowlines
o Field development to a subsea manifold or production facility
Gathering Lines
o Connecting multiple flowlines to a production facility
Export Pipeline
o Transport from a production facility to domestic or international market
Pipeline Route Selection In Subsea
Route Selection – Overview
Pipeline Route Characterization
Landfall and platform approaches
Length, kilometer post and
intermediate stations
Changes in alignment and elevation profile
System Environment
Characterization
Political and social factors
Physical and environmental factors
Engineered systems
Route Selection – Seabed Characteristics
Bathymetry & Slope
Soil Properties
Type
Index & strength
Spatial distribution
Seabed Mobility
Sediment Transport
Sandwave migration
Scour
Pipeline Design 41
Seismic
o Faulting
o Liquefaction
Mass
o Slides
o Spreads
o Falls
o Flows
Subsurface
o Shallow gas
o Pockmarks
o Subsidence
Subsea vents
o Pinnacles
Route Selection – Physical Environment
Currents
Systems, tidal, delta, loop
Surface
Waves
Wind induced
Shallow water, breaking
Bathymetry, refraction, wave crest orthogonality
Internal
Pycnocline [density] ø (water temp., salinity)
Seabed Use And Obstacles Oil and gas industry developments
Communications
Mobile and fixed gear fishing zones
Shipping traffic lanes
Military exercise zones
Military/civilian dumping grounds
Mining, dredging zones
Expected or anticipated future operations, developments
Shipwrecks
Unique Features
Ice gouging
Strudel Scour
Permafrost
1.11 Pipeline Shore Approaches
A subsea or marine pipeline reaches a landfall by the way of a shore approach. It is to be noted that the
shore approach is shallower than the rest of the pipelines lying in seabed. The pipes on the shoreline are
more prone to wave action and long shore currents and therefore more care has to be taken in laying and
connecting it to the onshore facilities.
42 Offshore Pipeline Systems
Due to the variability of the coastal environment, there are many ways the shore approach constructions
are done, a few among them:
a) Trenched crossing of sandy beaches
b) Horizontal drilling
c) Rock shores
d) Tidal flats
e) Tunnels
The installation of pipelines from offshore through shallow water to a beach always poses challenges.
The rapidly eroding clay cliffs along coastline, about 1 to 2 metres of cliff disappears into the sea.
Therefore it is necessary that the pipeline be installed deep within the cliff.
The solution was tom install a tunnel to carry the pipeline from the processing facility drawn into a tie-
in pit on the beach. A sheet piled cofferdam extended the pipeline trench from the tie-in pit through the
tidal zone of the beach to 60 meters beyond low water level.
Figure A18
Shore pipeline trench
The offshore trench was excavated using the cutter section dredger, and backfilling the trench was
performed using the trailing suction hopper dredger, which also carried out pre-sweeping of offshore
sand dunes. Rock placement at the pipeline crossing and in the near shore section was executed with a
side stone dumping vessel with rock
Figure A19
Pipeline Trenching by vessel
Construction Techniques Used In Water Crossing
The different steps (drilling the pilot hole, pre-reaming and pullback) and techniques involved in
achieving water crossing of a pipeline are shown in the following figures.
Pipeline Design 43
Figure A20
Construction Steps Used in Water Crossings
44 Offshore Pipeline Systems
Figure A21 Figure A22
Cutting the pull head of the Conduit Drilling Sting down Protective Casing
Figure A23 Figure A24
HDPE Pipeline Installation Shore-Pull Pipe Stringing
Figure A25 Figure A26
Post Trenching Pre-Dregde / Post-Trench
Pipeline Design 45
Figure A27
Shore Trenching of pipeline
46 Offshore Pipeline Systems