Petroleunm Pipeline Design (Graduation Project)

Supervisor:
Prof.Mostafa El-Sallak
DESIGN OF PETROLEUM PIPELINE
Graduation Project 2016
Mechanical Power Dep.

Acknowledgement
1
DESIGN OF PETROLEUM PIPELINE
Graduation Project 2016
Prepared by:
1-Ahmed Abd El-Azez Fouad
2-Amr Adel Abd El -Tawab
3-Ibrahim Sayed Abd El-Rahman
4-Islam Mostafa El-Hawary
5-Kholoud Mohammed Ahmed
Supervised by:
Prof.Mostafa El-Sallak

Acknowledgement
2
Acknowledgement
We especially wish to acknowledge the following:
We sincerely acknowledge our thanks Prof. Mostafa El-sallak for
guiding us and giving us his valuable time and advice. He always
enriched us with his knowledge and gave us the necessary input to
carry out this work. We are grateful to him for his extra efforts and for
being patient with us.

Contents
3
Contents
Contents........................................................................................................................................................3
Abbreviations................................................................................................................................................6
CODES/STANDARDS, REGULATIONS AND UNITS..........................................................................................7
Units System .................................................................................................................................................8
Introduction ..................................................................................................................................................9
Project Objective.........................................................................................................................................11
1.Preliminary data and routing consideration............................................................................................12
1.1.Fuel properties (Kerosene) ...........................................................................................................12
1.2. Design Principles Material Selection and Corrosion Protection ..................................................13
1.3. PIPELINE ROUTING CONSIDERATIONS.........................................................................................15
2.Hydraulic Study........................................................................................................................................20
2.1.Introduction..................................................................................................................................20
2.2.Project Data ..................................................................................................................................20
2.3.Hydraulic Calculation ....................................................................................................................20
2.4.Cost analysis to determine the optimum diameter:.....................................................................25
3.Pump station Design................................................................................................................................26
3.1. Introduction .................................................................................................................................26
3.2. Initial pump station:.....................................................................................................................26
3.2.1. Hydraulic Gradient Line (HGL) ..................................................................................................27
3.3. Ultimate pump stations: ..............................................................................................................30
3.3.1. Hydraulic Gradient Line (HGL) ..................................................................................................30
3.4.Booster pump ...............................................................................................................................34
4.Stresses ....................................................................................................................................................40
4.1. Above ground section..................................................................................................................40
4.2.High way and railway stresses ......................................................................................................44
4.5. Stress analysis for special parts....................................................................................................69
5.Corrosion Protection................................................................................................................................80
5.1.Introduction..................................................................................................................................80
5.2.Overview.......................................................................................................................................80
5.3.Corrosion Control..........................................................................................................................82
5.4.Cathodic Protection (CP)...............................................................................................................82
5.5.Calculations...................................................................................................................................85

Contents
4
6.Pressure Tests..........................................................................................................................................89
6.1.Purpose.........................................................................................................................................89
6.2. Main types of pressure tests........................................................................................................89
6.3. Hydrostatic Test main Procedures:..............................................................................................89
6.4. Test sections.................................................................................................................................90
6.5. Test Equipment............................................................................................................................92
6.6. Requirements Prior To PRESSURIZING.........................................................................................93
6.7. DURATION OF HYDROSTATIC TEST ..............................................................................................94
6.8. PRESSURE HOLD PERIOD..............................................................................................................94
6.9. STRENGTH TEST............................................................................................................................94
6.10. LEAKTIGHTNESS TEST.................................................................................................................95
6.11. ACCEPTANCE of leaktightness test ............................................................................................95
6.12. Depressurization ........................................................................................................................95
6.13. Hydrostatic test for the project .................................................................................................96
6.14. Example for the strength test result graph................................................................................97
6.15. Example for the leaghtightness test result graph......................................................................98
6.16. Actual photo to Hydrostatic test................................................................................................99
7.Pipeline Welding & NDT.........................................................................................................................100
7.1. General.......................................................................................................................................100
7.2. Welding Techniques...................................................................................................................100
7.3. Weld joint Design.......................................................................................................................101
7.4.NDT .............................................................................................................................................103
7.5. Most Butt-Weld Defects Found by NDT.....................................................................................109
7.6. Rejection criteria of welding in pipes (Based on API 1104) .......................................................110
8.Pipeline Cleaning....................................................................................................................................112
8.1. Introduction ...............................................................................................................................112
8.2. Methods of cleaning pipeline ....................................................................................................114
8.3.Pipe line launcher and receiver ..................................................................................................118
9.Valve Stations.........................................................................................................................................121
9.1. Introduction ...............................................................................................................................121
9.2. Usage..........................................................................................................................................121
9.3. Control on valves along the pipeline .........................................................................................121
9.4. Mainline Valve Locations ...........................................................................................................121

Contents
5
9.5. Types of Valves used in pipeline systems: .................................................................................122
9.6. Valve Vaults (rooms)..................................................................................................................126
9.7.Conclusion :.................................................................................................................................126
10.Surge Cause and Effect ........................................................................................................................127
10.1. Introduction .............................................................................................................................127
10.2. Pressure-relief valves...............................................................................................................129
10.3. Bleed Off of Air and Breaking Vacuum.....................................................................................129
10.4. Surge Calculations:...................................................................................................................130
10.4.1. System calculations...............................................................................................................131
11.Safety ...................................................................................................................................................133
11.1. Introduction .............................................................................................................................133
11.2. Pipeline Safety Principles.........................................................................................................133
11.3. Pipeline Safety Performance Results .......................................................................................135
11.4. Pipeline Performance Results Takeaways................................................................................140
12.Drawings ..............................................................................................................................................141
12.1. Introduction .............................................................................................................................141
12.2. Drawing code ...........................................................................................................................141
References ................................................................................................................................................143

Abbreviations
6
Abbreviations
MTY million Ton per Year
API American Petroleum Institute
ROW Right Of Way
ASME American Society of Mechanical Engineers
AWS American Welding Society
CP Cathodic Protection
ID Inside Diameter
MAOP Maximum Allowable Operating Pressure
OD Outside Diameter
P/L Pipeline
km Kilometer
SMYS Specified Minimum Yield Strength
TOP Top of pipe
NDT Non Destructive Test
FEA Finite Element Analysis
SCADA supervisory control and data acquisition

CODES/STANDARDS, REGULATIONS AND UNITS
7
CODES/STANDARDS, REGULATIONS AND UNITS
Applicable Codes and Standards
The design of the offshore flow lines shall meet the requirements of ASME B31.8,
which shall be considered as the governing design code.
In addition, the following codes and standards shall also be visited for the pipeline
design:
American Petroleum Institute (API)
API 5L Specification for Line Pipe, Forty-fourth Edition
API RP-1102 Steel Pipelines Crossing Railroads and Highways, 2007
API 1104 Welding of Pipelines and Related Facilities
American Society of Mechanical Engineers (ASME)
ASME B16.5 Pipe Flanges and Flanged Fittings
ASME B31.3 ASME Code for Pressure Piping
ASME B16.9 Factory-Made Wrought Butt welding FITTINGS
American Welding Society (AWS)
AWS 5.1 Specification for Carbon Steel Electrodes for Shielded Metal Arc
Welding

Units System
8
Units System
The standard international (SI) system of units shall be used throughout the design.
In addition, the following units listed in Table may also be used.
Property Units Designation
Length
kilometer Km
meter M
millimeter Mm
Pipe Size inch In or ”
Area square millimeters or meters (as appropriate) mm2
or m2
Pressure
Pounds per square inch (gauge) Psig
bar gauge Barg
Temperature degree Celsius C
Force Newton or kilo-Newton or metric Tonnes N or kN or Tons
Mass kilogram Kg
Volume cubic meters m3
Volumetric flow (Liquid) cubic meters per hour m3
/h
Density kilogram per cubic meter kg/m3
Velocity meters per second m/s
Kinematic viscosity square millimeters per second (centistoke) mm2
/s(Cst)
Time
second S
minute Min
hour H

Introduction
9
Introduction
Crude Oil and Refined Products Transportation methods
Crude oil must be moved from the production site to refineries and from
refineries to consumers. These movements are made using a number of
different modes of transportation. Crude oil and refined products are
transported across the water in barges and tankers. On land crude oil and
products are moved using pipelines, trucks, and trains.
Waterborne Transportation
Crude oil tankers are used to transport crude oil from fields in the
Middle East, North Sea, Africa, and Latin America to refineries around
the world. Product tankers carry refined products from
refineries to terminals.
As of 2006:
 The world tanker fleet had 4,186 vessels with a carrying capacity of 358.8 Mdwt.
 84% of the tanker fleet were owned by independent tanker companies.
 The average age of the fleet was 11.9 years.
 68% of the vessels are double hull ships.
Oil Spills
Although they get most of the publicity, oil spills only account for 12% of all spills. The major
cause of ocean oil pollution is industrial waste (61%). Tanker accidents contribute 5% and
tanker operations account for 7%. Other shipping accounts for 14%. Better operations and
improved ship design have helped reduce the number of large spills. During the decade from
1985-1994, the frequency of large spills decline by57%.
Storage Facilities
Crude oil and refined products are stored in tanks for shipment to other
locations or processing into finished products. There are four basic types of
tanks used to store petroleum products: (1) Floating Roof Tank used for crude
oil, gasoline, and naphtha, (2) Fixed Roof Tank used for diesel, kerosene,
catalytic cracker feedstock, and residual fuel oil, (3) Bullet Tank used for normal butane,
propane, and propylene, and (4) Spherical Tank used for isobutene and normal butane. The
amount of crude oil and refined products in storage is reported by Energy Information
Administration.

Introduction
10
Oil Pipelines
Pipelines are the most efficient method to transport crude oil and refined products.
Pipelines are used to move crude oil from the wellhead to gathering and processing
facilities and from there to refineries and tanker loading facilities. Product pipelines ship
gasoline, jet fuel, and diesel fuel from the refinery to local distribution facilities. Crude oil is
collected from field gathering systems consisting of pipelines that move oil from the wellhead
to storage tanks and treatment facilities where the oil is measured and tested. From the
gathering system the crude oil is sent to a pump station where the oil delivered to the
pipeline. The pipeline may have many collection and delivery points along route.
Booster pumps are located along the pipeline to maintain the pressure and keep the
oil flowing. The delivery points may be refineries, where the oil is processed into
products, or shipping terminals, where the oil is loaded onto tankers. A pipeline may
handle several types of crude oil. The pipeline will schedule its operation to ensure that the
right crude oil is sent to the correct destination. The pipeline operator sets the date and place
when and where the oil is received and the when the oil will arrive at its destination. Crude oil
may also move over more than one pipeline system as it journeys from the oil field to the
refinery or shipping port. Storage is located along the pipeline to ensure smooth continuous
pipeline operation.
Importance of pipeline
Pipelines are the safest and most efficient means of transporting large quantities of crude oil
and natural gas over land as mentioned above.
How we are so sure pipelines are the most efficient way to transport crude oil and natural gas
over land?
Pipelines simply make sense
 Large-scale transportation of natural gas by tanker truck or rail is not feasible (60
million liters per day, for example).
 Pipelines are more cost-effective than the alternative transportation options
 They require significantly less energy to operate than operating trucks or rail and
have a much lower carbon footprint
 Underground pipelines are safe, unaffected by weather.
 Cost efficiency for medium and long-haul transportation, with no need for
handling operations. For comparison purposes, the average cost per metric ton
per 100 kilometers is :
• Pipeline: €1.8 to €2.1.
• Train (2,000 tons): €2.7.
• Barge: €2.7 to €4.1.
• Truck (38 tons): €4.1

Project Objective
11
Project Objective
The present project aims to design a new offshore kerosene transmission pipeline system from
site (A) to site (B). The new pipeline system is about 260 Km long, operates at a maximum
design pressure of (70) bar with an initial capacity of (4) million standard cubic meter per year
and ultimate capacity of (6) million standard cubic meter per year.
This report covers the mechanical design of the offshore 18" kerosene pipeline system between
site (A) and (B), in terms of the following topics:
 Hydraulic study.
 Pump station design.
 Pipeline stress analysis.
 Cathodic protection.
 Weld test and NDT.
 Pressure test.
 Cleaning system.
 Valve station.
 Surge
Hint
All drawing sheets are separated in drawing booklet.

Chapter 1
12
Chapter 1
Preliminary data and routing consideration
1.1. Fuel properties (Kerosene)
Physical Description: A pale yellow or clear oily liquid.
Chemical Description:
A complex mixture of hydrocarbons, usually containing 10 to 16 carbon atoms per
molecule with the average being 12. The average chemical composition by percent Is:
35 percent alkanes (paraffin).
60 percent cyclic alkanes (naphthenic).
15 percent aromatics
A.S.T.M
Definition:
A light distillate intended for use in burners of the vaporizing type in which the oil is
converted to a vapor by contact with a heated surface or by radiation. High volatility is
necessary to ensure that evaporation proceeds with a minimum of residue.
Constants:
Flash point l00°-165°F (38-74°C).
Auto-ignition temperature: 444°F (229°C).
6. 879 to 7. 085 pounds per gallon.
Vapor density: 4.5 times that of air.
Pour point: 0°F (-18°C).
Viscosity: See graph 1.
Density range: 0.80 to 0.875 (see graph2).
Average boiling range: 345-510°F (174-266°C).

Chapter 1
13
Graph1 Graph 2
1.2. Design Principles Material Selection and Corrosion Protection
1.2.1. Pipe Material selection
Material selection shall be optimized, considering investment and operational costs, such that
Life Cycle Costs (LCC) are minimized while providing acceptable safety and reliability.
The following key factors apply to materials selection:
 Primary consideration shall be given to materials with good market availability and
documented fabrication and service performance.
 The number of different material types shall be minimized considering costs,
interchangeability and availability of relevant spare parts.
 Design life.
 Operating conditions.
 Experience with materials and corrosion protection methods from conditions with
similar corrosivity.
 System availability requirements.
 Philosophy applied for maintenance and degree of system redundancy.

Chapter 1
14
 Weight reduction.
 Inspection and corrosion monitoring possibilities.
 Effect of external and internal environment, including compatibility of different
materials.
 Evaluation of failure probabilities, failure modes, criticalities and consequences.
Attention shall be paid to any adverse effects material selection may have on human
health, environment, and safety and material assets.
 Environmental issues related to corrosion inhibition and other chemical treatments.
 For main systems where materials/fabrication represent significant investments and/or
operational costs, an LCC analysis shall be basis for material selection.
1.2.2. Corrosion allowance
For carbon steel piping, a corrosion allowance of 3 mm shall be used, unless higher corrosion
allowances are required.
Recommendation:
For submarine pipeline systems a total corrosion allowance of 10 mm is recommended as a
general upper limit for use of carbon steel. Carbon steel can be used in pipelines where
calculated inhibited annual corrosion rate is less than 10 mm divided by design life. Otherwise
corrosion resistant alloys, solid or clad or alternatively flexible pipe, should be used. For
pipelines with dry gas or dry oil, no corrosion allowance is required. Corrosion during
installation and testing prior to start-up shall be considered.
So we select API 5L X52 (most popular use in commercial Kersone pipeline)
Property Value Units
Density 7850 kg/m3
API 5L Specified Minimum Yield Strength
API 5L X52
359 N/mm²
API 5L Specified Minimum Tensile Strength 455 N/mm²
Poisson Ratio 0.3 -
Young’s Modulus of Elasticity 207 kN/mm²
Coefficient of Linear Thermal Expansion 11.7E-6 per C
Thermal Conductivity 45.35 W/m.K
Pipe Absolute Roughness 0.05 Mm

Chapter 1
15
1.3. PIPELINE ROUTING CONSIDERATIONS
1.3.1. Pipeline Route selection
The pipeline route selection could be based upon the known Geographic Information
system, as well as the actual site survey and scouting (could also make use of Google-
earth software desktop revelations), taking into consideration the following:
 The existing pipelines/facilities located across the work area, as well as the
applicable landmark coordinates.
 Shortest and most direct route between terminals , whilst avoiding physical
obstacles and populations areas of significant importance taking into
considerations the requirements of the pipeline design code to promote pipeline
safety .
 Economic considerations of the pipeline construction, and availability/vicinity of
the required access roads.
 Practicality of securing permanent access for inspection, maintenance, repairs.
 Hazardous nature, pressure and inventory of pipeline contents.
 Archaeological constraints.
 Future developments of the areas surrounding the pipeline corridor.
 Surface and sub-surface land topography, and the relevant hydrographical
conditions.
 Environmental impact assessment findings.
1.3.2. Pipeline Routing
The pipeline routing shall generally avoid areas in the vicinity of commercial, industrial
or military enterprises and areas frequented by human dwellings to promote safety of
the pipeline and the surrounding facility and/or human population. Where pipelines are
inevitably running in the vicinity of such areas, it is always advisable to remain at least
200 m away from such areas, otherwise extra safety measures should be exerted
according to the applicable design code, hence the definition of “the safety location
class” introduced by ASME B31.8 in order to set the criticality of the pipeline portion
with respect to the surrounding area/facility nature and where applicable density (in
case of buildings for instance).
Hot induction bends are likely to be used at the pipeline planimetry changes of
direction: hot bends radius shall be at least equal to 5 times “NPS” to ensure pipeline
pigs passage. Nevertheless cold bends could in some cases substitute hot bends
wherever revealed necessary by the stress analysis to keep the pipeline “in column” or
axially restrained.

Chapter 1
16
Along the buried pipeline profile, any slope change shall be preferably achieved by the
one of the following methods:
 Naturally (elastically), if the resulting radius of curvature is more than the
pipeline minimum elastic bend radius.
 Field bending the original line pipe “cold Bend”.
 Hot bends, wherever excavation/backfilling to adjust/smoothen the natural
ground profile is not possible or practical.
At terminals, buried pipeline shall emerge from ground by means of swan-neck configuration
composed of two hot bends 45o (most common bend angle value).
1.3.3. Pipeline Installation and ROW
Pipeline installation by direct burial, the pipeline is buried into natural ground following
as much as possible the natural profile (elastic bending), with the use of cold and/or hot
bends wherever required in the pipeline profile to avoid excessive cover depths.
The pipeline right-of-way shall range between 20m and 30m wide, depending on the
adopted trenching method and the construction equipment.
Pipeline markers shall be installed along the pipeline route intervals of 500 m in open
areas and at every direction change.
For normal excavation, the pipeline shall be buried below the minimum depth of cover
defined by the relevant design code [Appendix 2] based on the nature of the involved
area and the applicable pipeline route location class [Appendix 1]. Any Increase beyond
these depths shall be justified either by the local jurisdictional authorities or the pipeline
elastic bend radius to eliminate the need for cold/hot bends in the pipeline profile.
Table gives a general idea about the most common minimum cover depths (to T.O.P)
Adopted for the pipeline buried installation.
Location Cover Depth
Normal ground Rocky ground
Areas of no significant human activities 1.0m 0.6m
Agricultural land(1) 1.0m 0.8m
Canals, rivers, waterways(2) 2.0m 1.0m
Major Roads(4) 1.5m(3) 1.0m
Rail ways 2.0m 1.0m
Residential, industrial and commercial areas 2.0m 1.2m
Table pipeline minimum cover depths
Note 1: In all cases, cover shall not be less than the depth of normal cultivation.
Note 2: Cover to be from the lowest anticipated bed.

Chapter 1
17
Note 3: To be increased to 2.0m under high traffic inter-regional highways.
Note 4: Any road with an asphalted wearing surface.
1.3.4. Aboveground pipeline installation:
The pipeline could be either laid grade (not preferable) or installed on pipe supports
(concrete sleepers or steel posts) in a more profile-controlled manner, and in such case
close attention should be said to the pipeline stress analysis and thermal growth
control. For that purpose adequately sized and distributed horizontal or vertical
expansion loops would be foreseen along the pipeline length to safeguard the
generated stresses and loadings at terminals.
1.3.5. Pipeline Crossings
Generally pipeline crossings could vary between track load, main asphalt roads,
highways, and irrigation canals, Rivers/lakes, swaps or low grounds, in addition to
existing pipelines/cables or other infra-structures.
The primary aspect for the selection of the crossing execution is the safety and integrity
of the new pipeline as well as the existing asset or facility so that neither would be
breeched upon any intervention or maintenance works required on the new pipeline
and existing asset or facility.
The most common crossing methods for pipeline crossings are:
 Open cut, where asset (road or canal) is to restored to its original conditions
after crossing execution ensuring safety and the crossing and crossed entities.
 Horizontal Direction Drilling (HDD) see figure

Chapter 1
18
Figure 1.1
 Boring, where large pits are dug on either side of the road or waterway to be
crossed, and lined with sheet piles to create a safe workplace for the boring
machine that is lowered in on one side to push the pipeline casing through the
natural ground under the crossing by means of rotating continuous flights
(spiral) within the casing steel pipe. Then the new pipeline is pulled within the
casing (usually two sizing more pipe) with end seals and plastic insulators
installed in between the casing and the new pipe. Unlike HDD, Boring techniques
are limited to relatively short crossing lengths (up to 60-80 m depending on size
and thrust force).
In general, crucial or heavy-traffic highway crossing shall be performed by HDD
or boring techniques to avoid disturbing the traffic flow unless the local
jurisdictional consent open/cut.
The pipeline under road crossings shall comply with the requirements of API RP-
1102 expected traffic live loads.
Concrete slab shall be installed over the pipeline at crossing location for
identification and protection purposes.

Chapter 1
19
Crossing angle is to be kept as practical as possible perpendicular to the road
centerline, unless completely unavoidable, and all pipes used under crossings
shall be straight, with no bends permitted underneath.
For watercourses crossings constructed by open/cut techniques, the pipeline
static stability under buoyancy forces shall be assessed to establish need for the
concrete coating or other stabilizing measures.
The layout of pipeline

Chapter 2
20
Chapter 2
Hydraulic Study
2.1. Introduction
For any pipeline project the total cost of the whole project is the most important thing and
must be taken in consideration to decide whether the project is feasible or not, so we aim to
transport the required amount of kerosene by least amount of money, this cost includes
maintenance, operation for the line, pumping, electricity used, salary, wages, taxes and
insurance. But the most important thing is the total cost of the pipe’s material as well as the
cost of pump station.
The following calculation is used to determine the optimum used diameter with respect to cost
and use.
2.2. Project Data
Material pipe: API x52
Total length of Pipeline: 260 Km
Pdischarge=5bar
Fluid: Kerosene
Properties:
ρ=800 kg/m3
ν=2.4 centistoke
Toperating=50oc
The initial amount of kerosene = 4 MTY
The ultimate amount of kerosene = 6 MTY
Service Factor = 0.82 (number of Working days = 300 days)
2.3. Hydraulic Calculation
𝑄𝑖𝑛 =
𝑖𝑛𝑡𝑖𝑎𝑙 𝑎𝑚𝑜𝑢𝑛𝑡∗106∗1000
7200𝜌
(1)

Chapter 2
21
Where:
Qin: initial flow rate (m3/hr)
Initial amount: (MTY)
ρ: Density (kg/m3)
(1) This equation is rate equation (Q/time) but in the used equation.
Qin=694.44 m3/hr
𝑄 𝑢𝑙𝑡 =
𝑢𝑙𝑡𝑖𝑚𝑎𝑡𝑒 𝑎𝑚𝑜𝑢𝑛𝑡 ∗ 106
∗ 1000
7200𝜌
Where:
Qin: Ultimate flow rate (m3/hr)
Ultimate amount: (MTY)
ρ: Density (kg/m3)
Qult=1041.66 m3/hr
For Best economy and operation velocity must be between 1.75 to 3 m/s at ultimate state.
𝐷 = √
𝑄 𝑢𝑙𝑡
1.824𝑣
(2)
Where:
D: Inner Diameter (inch)
Qult : Ultimate flow rate (m3/hr)
V: velocity (m/s)
Dmin=13.79 " at v=3m/s
Dmax=18 “at v=1.75 m/s
(2) This equation is continuity equation but it is adjusted with the used units.
From the table of standard of API of pipes diameters must be within the following range = {14,
15, 16 and 17}

Chapter 2
22
We will make hydraulic analysis cost estimation for these three diameter cases. So we will
choose the diameter according to best economic solution.
Head loss Equation for Turbulent flow
𝒉 𝒇 = 𝟏𝟕. 𝟓𝟒𝟐𝟓
𝝂 𝟎.𝟐𝟓 𝑳𝑸 𝟏.𝟕𝟓
𝒅𝒊
𝟒.𝟕𝟓 (3)
hf : Head loss in pipes in meters.
ν: kinematic Viscosity of liquid in centistoke .
L : total length of pipe in Km.
Q: flow rate in m3/hr.
di :inner diameter of pipe in inches .
(3) This equation is modified equation for Darcy equation which is used practically.
First Diameter
Din=14’’
Initial flow state:
𝑣 =
𝑄 𝑖𝑛
1.824∗𝐷𝑖𝑛
2 (4)
Where:
V: flow velocity (m/s)
Qin: initial flow (m3/hr)
Din: Diameter meter (inch)
(4) This equation deduce from equation 2.
V= 1.9424 m/s
Re=287809 >4000 Turbulent flow
hf=1918 m
Pf=hf*ρ*g*10-5=150.53 bar

Chapter 2
23
Ptot=Pf+Pd=155.53 bar
Ultimate flow state:
V= 2.913 m/s
Re =431713.4633>4000 Turbulent flow
hf=3899.68809m
Pf=hf*ρ*g*10-5=306.0475 bar
Second Diameter
Din=15’’
Initial flow state
V= 1.692 m/s
Re=268621.7105 >4000 Turbulent flow
hf=1382.1174 m
Pf=hf* ρ*g*10-5=108.4686 bar
Ultimate flow state
V= 2.538 m/s
hf=2809.989 m
Pf=hf* ρ*g*10-5=220.528bar
Third Analysis
Din=16’’
Initial flow rate

Chapter 2
24
V= 1.487 m/s
hf= 1017.205m
Pf=hf ρ*g*10-5=79.83 bar
Ultimate flow rate
V= 2.23 m/s
hf=2068.08444 m
Pf=hf* ρ*g*10-5=162.303bar
Fourth Analysis
Din=17’’
Initial flow rate
V= 1.317 m/s
hf= 762.686 m
Pf=hf ρ*g*10-5=59.8556 bar
Ultimate flow rate
V= 1.976 m/s
hf=1550.621 m
Pf=hf* ρ*g*10-5=121.6927 bar

Chapter 2
25
2.4. Cost analysis to determine the optimum diameter:
The cost of the project mainly divided to three types of costs:
Fixed cost =fn(weight of pipe)
Running cost=fn (pumping power)
Maintance cost=0.25 fixed cost
Din Fixed cost run cost run and main cost Capital cost
Inch $ $/year $/year $
14 10701626 96094502 98769908.5 109471534.7
15 11949994 70089922 73077420.38 85027414.77
16 13262891 52385110 55700832.44 68963723.88
17 14640317 40036382 43696461.74 58336779.07
Table 2.1
Figure 2.2
From the cost analysis found the optimum diameter is 17’’
Notes about cost analysis
1-the prices is used in this study from internet.
2-the detailed calculations for costs in excel sheet in CD the previous table is only resulted
table.
0
20000000
40000000
60000000
80000000
100000000
120000000
14 15 16 17 18
cost($)
Diameter (inches)
cost analysis
initial cost
running and maintaince cost
captial cost

Chapter 3
26
Chapter 3
Pump station Design
3.1. Introduction
- At first the number of pump stations have to be determined by dividing the total
pressure by the maximum allowable operating pressure (MAOP) , then divide the
total head by the number of pump stations to determine the head of each pump
station .
- The number of pumps per pump station have to be determined by using the best
economical solution method by assuming the overall efficiency for the pump around
80 – 85 % , specifying the specific speed of the pump and using it with the total
specific speed to determine the number of pumps per pump station and the
connection type, (series, parallel, both) .
3.2. Initial pump station:
Design Parameters:
Qin = 700 m3
/hr
hf =760 m
Pf=60 bar
Pd=5 bar
Pt =Pf+Pd=65 bar
MAOP = 70 bar
Determination of number of pump stations:
PD + (PD - PS) + (PD - PS) = PT
PD + (N – 1)(PD - PS) = PT
𝑁 =
𝑃𝑡 − 𝑃𝑠
𝑃𝐷 − 𝑃𝑠
𝑃𝐷 =
𝑃𝑇 − 𝑃𝑠
𝑁
+ 𝑃𝑠
Where N: number of pump stations
PD: Delivery pressure

Chapter 3
27
Ps: Suction pressure
𝑁 =
65 − 5
70 − 5
= 0.923 ≈ 1
At N=1
PD=PT=65 bar =660 m of water.
3.2.1. Hydraulic Gradient Line (HGL):
The total energy at any point in a pumping system may be calculated for a
particular rate of flow using Bernoulli’s equation
If some convenient datum plane is selected and the total energy, or head, at
various locations along the system is plotted to scale, the line drawn through
these points is called the energy gradient.
For initial flow state:
Figure 3.1
660
50
0
100
200
300
400
500
600
700
0 20 40 60 80 100 120 140 160 180 200 220 240 260
TotalHead(ofwater)(meter)
Length (Km)
HGL
at initial state
Qin=694.44 m3/hr
Notes:
Dymanic Head is
small so we neglect
it .

Chapter 3
28
Determination of number of pumps:
𝑁𝑠 =
2𝜋𝑁
60 √𝑄
(𝑔𝐻)
3
4
Ns,t=0.1919
Q=0.195 m3
/s
Taking ƞ0 = 0.85
Figure 3.2
Nsp = 0.55 & 1.5
for parallel
Nsp = Nst / Z1/2
Z = (
Nst
Nsp
)2
As , Nst <Nsp
So, Z always will be < 1
So, pumps will be in series.

Chapter 3
29
For series:
Nsp = Nst * Z3/4
Nsp α Z (number of pumps)
So, the smaller one will be taken
Nsp=0.55
Z= (
Nsp
Nst
)4/3
Z= 3.98 ≈4
Nsp=0.54
Ƞ0= 85 %
Q = 700 m3
/hr
Hp = 165 m
Heat transfer / HPH (3.3)
Figure 3.3

Chapter 3
30
3.3. Ultimate pump stations:
Qult = 1040 m3
/hr
hf = 1550 m
Pf = 122 bar
Pdelivery = 5 bar
Pt =127 bar
ht = 1290 m of water
Ps = 5 bar
N =
127−5
70−5
= 1.88 ≈ 2
Pd =
127−5
2
+ 5 = 66 bar = 672 m of water
Ps = 5 bar = 51 m of water
3.3.1. Hydraulic Gradient Line (HGL):
For Ultimate flow state:
Figure 3.4
660
68.52
690
41.28
0
100
200
300
400
500
600
700
800
0 20 40 60 80 100 120 140 160 180 200 220 240 260
TotalHead(ofwater)(meter)
Length (Km)
HGL
at Ultimate state
Qult=1041.66m3/hr
Notes:
Dymanic Head is small
so we neglect it .
124 km (position of pump station 2)

Chapter 3
31
1st
pump station:
Qult = 1040 m3
/hr
Qint = 700 m3
/hr
Qreq = Qult - Qint
Qreq = 340 m3
/hr
= 0.09445 m3
/s
The same head as in initial case will be taken
H = 660 m of water
Nst =
2π∗3000
60
√0.09445
(9.81∗660)3/4
= 0.134
Figure 3.5
Taking ƞ0 = 0.8
Nsp=0.37
For series:
Z = (
0.37
0.134
)4/3
= 3.87 ≈ 4

Chapter 3
32
Nsp = 0.379
Ƞ0 = 0.81
H = 165 m of water
Q = 340 m3
/hr
- High pressure pump (2)
WKF (2.6)(150/2)
Figure 3.6
2nd
pump station:
H = 685 m
Q = 1040 m3
/hr
 It’s a huge flow rate for one pump.
So, it will be divided by two. (Practically)
Q = 520 m3
/hr
= 0.144 m3
/hr
H = 685 m of water
Nst =
2𝜋∗3000
60
√0.144
(9.81∗685)3/4
= 0.161
Taking ƞ0 = 0.8

Chapter 3
33
Nsp = 0.35
For series :
Z = (
0.35
0.161
)4/3
= 2.82 ≈ 3
Nsp= 0.367
ƞ0 = 0.81
Q = 520 m3
/hr
H = 230 m of water
- High pressure pumps (2)
WKF(2.6)(150/2)
- 6 pumps
Figure 3.7

Chapter 3
34
Figure 3.8
3.4.Booster pump:
Q = 800 m3
/hr
H = 100 m
N = 1500 rpm
Nst =
2𝜋∗1500
60
√
800
3600
(9.81∗100)3/4
= 0.422
Taking ƞ0 = 0.82
For series:
Z = (
0.41
0.422
)4/3
= 0.93 ≈ 1
Nsp = 0.422
ƞ0 = 0.84
For parallel :
Z = (
0.422
0.41
)2
= 0.98 ≈ 1
Nsp = 0.422

Chapter 3
35
ƞ0 = 0.84
Figure 3.9
- Low pressure (1)
Omega/omega v(1.8)(200.520)
Figure 3.10

Chapter 3
36
Cavitation check:
For booster pump
Nsp = 0.422
σcr = 0.08
σav =
Patm−Pvap−Hms
Ht
Hms = Hss + Hfs
Hatm=10.33 m
Pvap=0.5 kpa
Hvap=0.064 m
Htot=100 m Figure 3.11
Hms=-15m
σavailable = 0.25266
σavailable > σcr (safe)
Summary
case Pump stations Head (H) Flow rate (Q) No. of pumps(Z)
Initial
1st
165 m 700 m3
/hr 4
Ultimate
1st
165 m 340 m3
/hr 4
2nd
230 m 520 m3
/hr 6
Table 3.12

Chapter 3
37
Selected pumps details from catalog (KSB Co.)
1. Initial Pump
Figure 3.13

Chapter 3
38
2. Ultimate pump
Figure 3.14

Chapter 3
39
3. Booster pump
Figure 3.14

Chapter 4
40
Chapter 4
Stresses
4.1. Above ground section
4.1.1. Generally
 The following information and calculations are based on ASME B31.4 -2012
 This code is applied to hydrocarbons, liquid petroleum gas, alcohols, and carbon
dioxide.
 The requirements of this Code are adequate for
Safety under conditions normally encountered in the
Operation of liquid pipeline systems. Requirements for all abnormal or unusual
conditions are not specifically provided for, nor are all details of engineering and
construction prescribed. All work performed within the Scope of this Code shall
comply with the safety standards expressed or implied.
4.1.2. Loads
4.1.2.1. Load Classifications
The design of a pipeline shall be based on consideration of the loads identified in this
section to the extent that they are significant to the proposed system and applicable to
the proposed installation and operation. Loads that may cause or contribute to pipeline
failure or loss of serviceability of the pipeline system shall be identified and accounted
for in the design. For strength design, loads shall be classified as one of the following:
(a) sustained
(b) occasional
(c) construction
a. Sustained Loads
Sustained loads are those arising from the intended use of the pipeline system and loads
from other sources. The weight of the pipeline, including components, fluids, slurries,
and loads due to pressure, are examples of sustained loads. Soil cover, external
hydrostatic pressure, and vibration due to equipment are examples of sustained loads
from other sources. Reaction forces at supports from sustained loads and loads due to

Chapter 4
41
sustained displacement or rotations of supports are also sustained loads. The
calculations of the sustained loads will be in the calculations section.
b. Occasional loads
Examples of occasional loads are those resulting from wind, snow, ice, seismic ,road and
rail traffic, temperature change, currents, and waves except where they need to be
considered as sustained loads (loads caused by temperature change may also be
considered sustained in some instances). Loads resulting from prestressing, residual
forces from installation, subsidence, differential settlement, frost heave, and the
settlement are included in occasional loads.
c. Construction Loads
Loads necessary for the installation and pressure testing of the pipeline system are
construction loads. Examples of construction loads include handling, storage,
installation, and hydro testing.
4.1.2.2. Application of Loads
Restrained Versus Unrestrained.
The restraint condition is a factor in the structural behavior of the pipeline and,
consequently, affects stresses and applicable stress limits. The degree of restraint may
vary with pipeline construction activities, support conditions, soil properties, terrain and
time. For purposes of design, this code recognizes two restraint conditions, restrained
and unrestrained.
(a) “Unrestrained” means that the pipe is free to displace laterally and to strain axially.
Unrestrained pipelines may include the following:
(1) Aboveground pipe that is configured to accommodate thermal expansion or support
movement
(2) Field bends and adjacent pipe buried in soft or unconsolidated soil
(3) An unbackfilled section of buried pipeline that is free to displace laterally or which
contains a bend
(4) Unanchored sections of pipe
(b) Restrained pipelines may include the following:

Chapter 4
42
(1) Sections of buried pipe
(2) Sections of aboveground pipe attached to closely spaced rigid supports, anchored at
each end and at changes in direction.
4.1.3. Sustained Loads
In the case of constant loads, the expected value of the load shall be used. In the case of
variable loads, the specified highest or lowest value shall be used, whichever is more
critical. In the case of load caused by deformation, the expected extreme value shall be
used.
4.1.3.1. Internal Design Pressure
The pipe and components at any point in the pipeline shall be designed for an internal
design pressure that shall not be less than the maximum steady state operating
pressure at that point, nor less than the static head pressure at that point with the
pipeline in a static condition. The maximum steady state operating pressure shall be the
sum of the static head pressure, pressure required to overcome friction losses.
4.1.3.2. Weight Effects
Weight effects combined with loads and forces from other causes shall be considered in
the design of pipelines. The effect of the combined weight of pipe, coating, and other
attachments (in air and submerged) on installation stresses and strains shall be
considered. Variability due to weight coating manufacturing tolerances and water
absorption shall also be considered
4.1.3.3. Temperature Effect
The design temperature is the metal temperature expected in normal operation. It is
not necessary to vary the design stress for metal temperatures between −20°F (−30°C)
and 250°F
(120°C).
The design temperature should be established considering temperature variations
resulting from pressure changes and extreme ambient temperatures. Consideration
should be given to possible conditions that may cause low temperatures on pipelines
transporting liquids that become gases at or near atmospheric conditions.

Chapter 4
43
4.1.4. Construction Loads
4.1.4.1. Installation Load
Loads induced during transportation, handling, storage, and lowering-in shall be
considered. Increases in external pressure during pressure grouting or decreases in
internal pressure during vacuum drying shall be considered as installation loads.
4.1.4.2. Hydrostatic Testing
Loads that occur during hydrostatic testing shall be considered. These loads include
weight of contents, thermal, and pressured end effect.
4.1.4.3. Combining of Loads
When calculating equivalent stresses or strains, the most critical combination of
sustained, occasional, construction, and transient loads that can be expected to occur
shall be considered.
Details of channel crossing
Figure 4.1

Chapter 4
44
4.2.High way and railway stresses
4.2.1. Generally
 These information and calculations are based on API 1102
 This recommended code, Steel Pipelines Crossing Railroads
and Highways, gives primary emphasis to provisions for
public safety
 This practice applies to welded steel pipelines
4.2.2. Design
To ensure safe operation, the stresses affecting the uncased pipeline must be accounted
for comprehensively, including both circumferential and longitudinal stresses. The
recommended design procedure is shown schematically It consists of the following
steps:
a) Begin with the wall thickness for the pipeline of given diameter approaching the
crossing. Determine the pipe, soil, construction, and operational characteristics.
b) Calculate the circumferential stress due to earth load, SHe.
c) Calculate the external live load, w, and determine the appropriate impact factor, Fi.
d) Calculate the cyclic circumferential stress, ΔSH, and the cyclic longitudinal stress, ΔSL
due to live load.
e) Calculate the circumferential stress due to internal pressure, SHi.
f) Check effective stress, Seff as follows:
1) Calculate the principal stresses, S1 in the circumferential direction, S2 in the
longitudinal direction, and S3, in the radial direction.
2) Calculate the effective stress, Seff.
3) Check by comparing Seff against the allowable stress, SMYS × F.
i) If any check fails, modify the design conditions in Item a appropriately and repeat the
steps in Items b through h. several figures give design curves for specific material
properties or geometric conditions. Interpolations between the design curves may be
done. Extrapolations beyond the design curve limits are not recommended

Chapter 4
45
Figure 4.2—Flow Diagram of Design Procedure for Uncased Crossings of Railroads and Highway
Satisfactory design
Pipe, operational,
Installation, and
Site characteristics
Calculate w: and calculate Fi:
Figure 4.9
Calculate circumferential
Stress due to earth load,
SHe, and
Figures 4.6, 4.7, and 4.8
Calculate cyclic circumferential
Due to live load, ∆SH:
Figures 4.10, 4.11, and 4.12; or
Figures 4.19 and 4.20
Calculate cyclic longitudinal due
to live load SL: Figures 4.13, 4.15
and 4.14; or Figures 4.17 and
4.16
Calculate the circumferential
Stress due to internal pressure
Using the Barlow formula,
SHi (Barlow)
SHi (Barlow) ≤ allowable
Calculate the principal stresses,
S1, S2, S3
Calculate effective stress, Seff:
Check for allowable Seff:
Optimal design?
Begin
Live load
External load
Earth load
Internal load
Fails
Fails Seff check
Design complete
No

Chapter 4
46
4.2.3.Uncased Crossings
The decision to use an uncased crossing must be predicated on careful consideration of
the stresses imposed on uncased pipelines, versus the potential difficulties associated
with protecting cased pipelines from corrosion. This section focuses specifically on the
design of uncased carrier pipelines to accommodate safely the stresses and
deformations imposed at railroad and highway crossings
4.2.3.1. General
The carrier pipe should be as straight as practicable and should have uniform soil
support for the entire length of the crossing.
4.2.3.2. Railroad Crossings
Carrier pipe under railroads should be installed with a minimum of cover, as measured
from the top of the pipe to the base of the rail, as follows (see Figure 4.3):
a) Under track structure proper. (2 m)
b) Under all other surfaces within the right-of-way or from the bottom of ditches. 3 ft
(0.9m)
c) For pipelines transporting Liquid Fuel, from the bottom of ditches. 4 ft (1.2 m)
Figure 4.3

Chapter 4
47
4.2.3.3. High way crossing
Carrier pipe under highways should be installed with minimum cover, as measured from
the top of the pipe to the top of the surface, as follows (see Figure 4.4).
a) Under highway surface proper. (2 m)
b) Under all other surfaces within the right-of-way. 3 ft (0.9 m)
c) For pipelines transporting liquid fuel, from the bottom of ditches. 4 ft (1.2 m)
Figure 4.4
4.2.4. Loads
4.2.4.1. Generally
A carrier pipe at an uncased crossing will be subjected to both internal load from
pressurization and external loads from earth forces (dead load) and train or highway
traffic (live load). An impact factor should be applied to the live load.
Other loads may be present as a result of temperature fluctuations caused by changes in
season; Pipe stresses induced by temperature fluctuations can be included.
4.2.4.2. External Loads
4.2.4.2.1. Earth Load
The earth load is the force resulting from the weight of the overlying soil that is
conveyed to the top of pipe. The earth load is calculated according to the procedures
widely adopted in practice for ditch conduits .Such procedures have been used in
pipeline design for many years and have been included in specifications adopted by
various professional organization this load is calculated for both railway and highway

Chapter 4
48
4.2.5. Railway crossing
4.2.5.1. Stresses Due to Live Load
The live, external rail load is the vehicular load, w, applied at the surface of the crossing.
It is recommended that Cooper E-80 loading of w = 13.9 psi (96 kPa) be used This is the
load resulting from the uniform distribution of four 80-kip (356-kN) axles over an area
20 ft by 8 ft (6.1 m by 2.4 m). The live external highway load, w, is due to the wheel load,
P, applied at the surface of the roadway. Wheel load from a truck’s single axle, Ps, or the
maximum wheel load from a truck’s truck with a single axle load of 24 kips (106.8 kN)
would have a design single wheel load of Ps = 12 kips (53.4 kN) and tandem axle set, Pt.
4.2.5.2 Impact Factor
It is recommended that the live load be increased by an impact factor, Fi, which is a
function of the depth of burial, H,
4.3. Calculations
4.3.1. Calculations of thickness
For both restrained and unrestrained pipelines, the circumferential (hoop) stress
due to internal pressure is
𝑺 𝒉 =
𝒑𝒊 𝑫
𝟐𝒕
𝑆ℎ = 𝐹 × 𝐸 × 𝑆𝑀𝑌𝑆

Chapter 4
49
circumferential (hoop) stress due
to internal pressure, psi (Mpa)
𝑺 𝒉
internal design gage pressure, psi
(bar)
𝒑𝒊
wall thickness of pipe, in. (mm)t
outside diameter of pipe, in. (mm)D
weld joint factorE
design factor based on nominal
wall thickness
F
specified minimum yield strength
of the pipe,
psi (Mpa)
SMYS
SMYS =359 Mpa
E=1 and F=0.9 (recommended)
𝑝𝑖 = 70 𝑏𝑎𝑟
𝐷 = 0.4318 + 2𝑡
Get 𝑡 𝑚𝑖𝑛 = 4.78 𝑚𝑚
𝑡 𝑛 ≥ 𝑡 𝑚𝑖𝑛 + 𝐴
Nominal design thickness𝒕 𝒏
Minimum thicknesstmin
Corrosion and milling tolerance
factors
A

Chapter 4
50
Corrosion = 3 mm
Milling tolerance factor = 12.5 percent of minimum thickness
From API standard table: t=12.7 mm =0.5 inch
Figure 4.5
4.3.2. Calculations of above ground section
4.3.2.1. Unrestrained Pipe
The longitudinal stress from pressure and external loadings in unrestrained pipe
is calculated as:
𝑆𝑙 =
𝑃𝑖 𝐷
40 𝑡
+
𝑖𝑀
𝑍
+
𝐹𝑎
𝐴

Chapter 4
51
The longitudinal stress from pressure
and external loadings
𝑆𝑙
Pi p internal design gage pressure, psi
(bar)
𝑃𝑖
outside diameter of pipe, in. (mm)𝐷
wall thickness of pipe, in. (mm)𝑡
section modulus of the pipe or of the
fitting outlet,
as applicable, in.3 (cm3)
𝑍
axial force, such as weight on a riser, lb
(N)
𝐹𝑎
metal area of nominal pipe cross
section, in.2 (cm2)
A
bending moment across the nominal
pipe cross
M
i component stress intensification in
plane of loading
limited by 0.75i ≥ 1. For
straight pipe, i 1.0.
i
𝐹𝑎 = 0 𝑎𝑠 𝑡ℎ𝑒𝑟𝑒 𝑖𝑠 𝑛o external force
𝑊 = 𝜌𝑠𝑡∀ 𝑔 (Distributed weight of the pipe)
Where
𝜌𝑠𝑡 = 7850 𝑘𝑔/𝑚3
∀=
𝜋
4
(𝐷𝑜2
− 𝐷𝑖2
) Volume of the pipe per length
W=1365.727 N/m

Chapter 4
52
𝑀 𝑚𝑎𝑥 =
𝑊
2
×
𝐿
2
𝑁. 𝑚
𝑀 𝑚𝑎𝑥 = 76822.166 𝑁. 𝑚
Where L is the span length =15 m
Z=
𝐼
𝑌
=
𝜋
64
(𝐷𝑜4−𝐷𝑖4)
𝐷0
2
= 0.03068153197 𝑚3
Where
I is the second moment of inertia
∴ 𝑺𝒍 = 𝟖. 𝟖 𝑴𝒑𝒂
𝑺 𝒉 =
𝒑𝒊 𝑫
𝟐𝒕
= 𝟏𝟐𝟔 𝑴𝒑𝒂
Check for safety for unrestrained pipes
√ 𝑆𝑙
2
+ 𝑆ℎ
2
+ 𝑆ℎ 𝑆𝑙 ≤ 0.75×SMYS
130.6225Mpa ≤ 269.25Mpa (SAFE)
Where F=0.75 for unrestrained case
𝑺 𝒄𝒐𝒎𝒃 = 𝒔 𝒉 + 𝒔𝒍+𝑬𝜶∆𝑻 − 𝝑𝑺 𝑯= 193.876 Mpa ≤ 0.75 SMYS=269.25 Mpa
Where
∆𝑻 = 40 𝑑𝑒𝑔𝑟𝑒𝑒 𝛼 = 11.7 × 10^(−6) mm/mm°C
E: young modulus
𝜗:Poisson ratio

Chapter 4
53
4.3.3. Stress Calculations of underground section
4.3.3.1. Stresses due to External Loads
4.3.3.1.1. Stresses due to Earth Load
The earth load is the force resulting from the weight of the overlying soil that is
conveyed to the top of pipe. The earth load is calculated according to the
procedures widely adopted in practice for ditch conduits .Such procedures have
been used in pipeline design for many years and have been included in
specifications adopted by various professional organizations this load is calculated
for underground, railway and highway
Calculations:
SHe =𝑲 𝑯𝑬 Be Ee γ D
Where
External diameter of pipe, in. or (mm).D
Circumferential stress from earth load,
in psi or (kPa)
She
Unit weight of soil, in lb/in.3
or
(kN/m3
).
γ
Excavation factor for circumferential
stress from earth load
Ee
Stiffness factor for circumferential stress
from earth load
𝑲 𝑯𝑬
Burial factor for circumferential stress
from earth load.
Be

Chapter 4
54
From charts and tables:
ValueVariablesFig.Factor
0.84D and bored
diameter
4.8Ee
2890t , D , E=3.4 MPA
(modulus of soil
section )
4.6𝑲 𝑯𝑬
0.92H and bored
diameter
4.7Be
D=18 ‘’, bored diameter =18 ‘’, H =2 m depth
18900 N/𝑚3
=γ
𝑺 𝒉𝒆=19.29 Mpa
By taking the same the longitude stress as the above ground stress
∴ 𝑺𝒍 = 𝟖. 𝟖 𝑴𝒑𝒂
Check for safety for unrestrained pipes
√ 𝑆𝑙
2
+ 𝑆ℎ
2
+ 𝑆ℎ 𝑆𝑙 ≤ 0.75×SMYS
24.88566 ≤ 269.25 (SAFE)

Chapter 4
55
Figure 4.6 – Stiffness Factor for Earth Load Circumferential stress, KHe
Figure 4.7 – Burial Factor for Earth Load Circumferential Stress, Be

Chapter 4
56
Figure 4.8– Excavation Factor for Earth Load Circumferential stress, Ee
4.3.3.1.2. Stresses Due to Live Load
4.3.3.1.2. a. Highway case
The applied design surface pressure, w (lb/in.2 or kN), then is determined as follows
𝑤 =
𝑃
𝐴 𝑝
Where
is the either the design single wheel load,
Ps, or the design tandem wheel load Pt,
in lbs (kN,.(
P
is the contact area over which the wheel
load is applied; Ap is taken as 144 in.2
(0.093 m2)
𝐴 𝑝
For the recommended design loads of
Ps = 12 kips = 12,000 lbs (53.4 kN)
Pt = 10 kips = 10,000 lbs (44.5 kN) the
Applied design surface pressures are as follows:
a) Single axle loading: w = 83.3 psi (574 kPa).
b) Tandem axle loading: w = 69.4 psi (479 kPa).
So single axle loading is more severe

Chapter 4
57
Impact Factor
It is recommended that the live load be increased by an impact factor, Fi, which is a function of
the depth of burial, H, of the carrier pipeline at the crossing. The impact factor for both railroad
and highway crossings is shown graphically in Figure 4.9.
The impact factors are 1.75 for railroads and 1.5 for highways, each decreasing by 0.03 per ft
(0.1 per m) of depth below 5 ft (1.5 m) until the impact factor equals 1.0
Figure4.9 recommended impact factor verses depth

Chapter 4
58
4.3.3.1.2. b. Railroad Cyclic Stresses
The cyclic circumferential stress due to rail load, ΔSHr, (psi or kPa), may be calculated as follows:
∆𝑆 𝐻𝑟 = 𝑊𝑘 𝐻𝑟 𝐺 𝐻𝑟 𝑁 𝐻 𝐹𝐼
Where
∆𝑆 𝐻𝑟 Cyclic Circumferential stress due to
railway psi (kpa)
𝒌 𝑯𝒓 is the railroad stiffness factor for cyclic
circumferential stress.
𝐺 𝐻𝑟 The railroad geometry factor for cyclic
circumferential stress.
𝑁 𝐻 the railroad single or double track factor
for cyclic circumferential stress
Fi the impact factor
W The applied design surface pressure, in
psi or kPa.
is From charts and graphs :
Factor Figure Variable Value
𝒌 𝑯𝒓 4.10 Thickness and D 200
𝑮 𝑯𝒓 4.11 Soil resilent
modulus (138
Mpa )
0.82
𝑵 𝑯 4.12 Double track
factor
1.18
𝐹𝐼 =1.675
W=96 Kpa
∆𝑆 𝐻𝑟=31.118 Mpa

Chapter 4
59
Figure.4.10 Railroad stiffness factor for cyclic circumferential Stress, KHr
Figure4.11 Railroad Geometry factor for cyclic circumferential Stress, GHr

Chapter 4
60
Figure 4.12 Railroad Double Track factor for cyclic circumferential Stress, NH
The cyclic longitudinal stress due to rail load, ΔSLr (psi or kPa) may be calculated as
follows:
∆𝑆 𝐿𝑟 = 𝑊𝑘 𝐿𝑟 𝐺 𝐿𝑟 𝑁𝐿 𝐹𝐼
WHERE
ΔSLr cyclic longitudinal stress due to rail load
𝑘 𝐿𝑟 the railroad stiffness factor for cyclic
longitudinal stress
𝐺 𝐿𝑟 the railroad geometry factor for cyclic
longitudinal stress
𝑁𝐿 the railroad single or double track factor
for cyclic longitudinal stress.
Fi the impact factor.
W the applied design surface pressure, in
psi or kPa

Chapter 4
61
𝒌 𝑳𝒓 4.13 t and D 300
𝑵 𝑳 4.14 D and H 1.02
𝑮 𝑳𝒓 4.15 D and H 0.8
𝐹𝐼 = 1.675
∆𝑺 𝑳𝒓=39.36 Mpa
Figure.4.13 Railroad Stiffness factor for cyclic Longitudinal Stress, KLr

Chapter 4
62
Figure.4.14 Railroad Double Track factor for cyclic Longitudinal Stress, NL
Figure 4.15 Railroad Geometry factor for cyclic Longitudinal Stress, GLr

Chapter 4
63
Check for safety:
𝑺 𝑯𝑰 =
𝑷(𝑫−𝒕)
𝟐𝒕
= 122.5 Mpa
Where
P internal pressure
D outer pipe diameter (18 inch )
T thickness (0.5 inch )
Circumferential:
𝑺 𝟏 = 𝑺 𝑯𝑬 + ∆𝑺 𝑯 + 𝑺 𝑯𝑰 = 172.9 Mpa
Longitudinal:
𝑺 𝟐= ∆𝑺 𝑳 − 𝑬 ∝ (∆𝑻) + 𝝑(𝑺 𝑯𝑬 + 𝑺 𝑯𝑰)=-14.9 Mpa
Radial:
𝑺 𝟑= − 𝒑=-7 Mpa
𝑺 𝒆𝒇𝒇.=√
𝟏
𝟐
((𝑺 𝟏 − 𝑺 𝟐) 𝟐 + (𝑺 𝟐 − 𝑺 𝟑) 𝟐 + (𝑺 𝟑 − 𝑺 𝟏) 𝟐 =184.5 Mpa ≤SMSY ×F=323.1Mpa (SAFE)
Where F=0.9 (restrained) SMSY=359 Mpa
High way stresses
The cyclic longitudinal stress due to highway vehicular load, ΔSLh (psi or kpa), may
be calculated from
The following:
∆𝑆 𝐿ℎ = 𝑊 𝐿 𝑅 𝑘 𝐿ℎ 𝐺 𝐿ℎ 𝐹𝐼

Chapter 4
64
Where
∆𝑆 𝐿ℎ The cyclic longitudinal stress due to
highway vehicular load
KLh the highway stiffness factor for cyclic
longitudinal stress
GLh the highway geometry factor for cyclic
longitudinal stress
R the highway pavement type factor
L the highway axle configuration factor
w The applied design surface pressure, in
psi or kpa.
The pavement type factor, R, and axle configuration factor, L, are the same as given in Table 2
𝒌 𝑳𝒉 4.17 Thickness
and
diameter
6
𝑮 𝑳𝒉 4.16 Diameter
and height
0.92
For no pavement, diameter greater than 12 inches as the diameter is 18 inches
𝐹𝐼 = 1.5
𝑅 = 1.1 𝐿 = 1
W=
𝑃
𝐴
=574.1
∆𝑆 𝐿ℎ = 5.22 Mpa

Chapter 4
65
Figure4.16 Highway Geometry factor for cyclic Longitudinal Stress, GLh
Figure4.17 Highway stiffness factor for cyclic Longitudinal Stress, KLh

Chapter 4
66
Figure 4.18
The stress due to highway vehicular load, (psi or kpa), may be calculated from
The following:
∆𝑆ℎℎ = 𝑊 𝐿 𝑅𝑘 𝐻ℎ 𝐺 𝐻ℎ 𝐹𝐼
Where
∆𝑆ℎℎ The stress due to highway vehicular load
𝑘 𝐻ℎ is the highway stiffness factor for stress
𝐺 𝐻ℎ the highway geometry factor for stress
R The highway pavement type factor.
L the highway axle configuration factor
W the applied design surface pressure, in
psi or kPa
The pavement type factor, R, and axle configuration factor, L, are the same as given in Table 2.
Factor Figure Variables Value
𝑮 𝑯𝒉 4.20 Diameter and
height
0.8
𝒌 𝑯𝒉 4.19 Thickness and
diameter
8

Chapter 4
67
𝐹𝐼 = 1.5 (Recommended)
∆𝑆ℎℎ = 6.06 𝑀𝑝𝑎
Figure4.19 -Highway stiffness factor for cyclic Circumferential Stress, KHh
Figure4.20 -Highway Geometry factor for cyclic Circumferential Stress, GHh

Chapter 4
68
Check for safety:
Circumferential:
𝑺 𝟏 = 𝑺 𝑯𝑬 + ∆𝑺 𝑯 + 𝑺 𝑯𝑰 = 147.8 Mpa
Longitudinal:
𝑺 𝟐= ∆𝑺 𝑳 − 𝑬 ∝ (∆𝑻) + 𝝑(𝑺 𝑯𝑬 + 𝑺 𝑯𝑰)=-49.1 Mpa
𝑺 𝑯𝑰 =
𝑷(𝑫−𝒕)
𝒕
= 122.5 Mpa
Radial:
𝑺 𝟑= − 𝒑=-7 Mpa
𝑺 𝒆𝒇𝒇.=√
𝟏
𝟐
((𝑺 𝟏 − 𝑺 𝟐) 𝟐 + (𝑺 𝟐 − 𝑺 𝟑) 𝟐 + (𝑺 𝟑 − 𝑺 𝟏) 𝟐 =179.6 Mpa ≤SMSY ×F =323.1Mpa (safe)

Chapter 4
69
4.5. Stress analysis for special parts
4.5.1. Expansion loop design
4.5.1.1. Introduction
The expansion loop is a common way to absorb temperature expansion and contraction in steel pipes.
Expansion loops can be fabricated from standard pipes and elbows.
Figure4.21 - expansion loop
4.5.1.2. Calculation
Calculation of main dimension
H=0.378 √
3 𝐸 𝑑 ∆𝐿
𝜎 𝑎𝑙𝑙
Where:
H: the length of the expansion loop
d: outer diameter
𝜎𝑎𝑙𝑙 : Allowable stress for the selected material
E: modulus of elasticity of material
∆𝐿 : Elongation in length due to temp. Difference
d= 0.457m
𝜎𝑎𝑙𝑙 =1.52E+08 Pascal (from ASME B31.3)

Chapter 4
70
E=2.07E+11 Pascal
∆𝐿=α* Linst * ∆t
Α=1.29E-05 m/(m*K)
Linst=100m (we calculated the required expansion loop for the
∆t=40 k
∆𝐿 =51.47 mm
So H= 3.6 m
And w=H/2=1.8 m

Chapter 4
71
4.5.2. Anchor design of sloped pipes of the mountain
Figure4.22
Design conditions:
Gradient: 𝜃 =30°
Nominal diameter: D=45.72 cm
Type of joint: push on type
Weight of the pipe: W=20485.5 N (calculated before taking span length 15 m)
Firstly: dimensions of the thrust block: L
If the allowable adhesion between the pipe and the block 𝜏 𝑎 = 50 N/𝑐𝑚2
, then 𝑙1the length
that will provide the sufficient adhesion
𝑙1 ≥
𝑊 sin 𝜃 cos 𝜃
𝜋𝐷τa
𝑙1 ≥ 1.2351 𝑐𝑚
If the allowable bearing strength of the soil is 𝑞 𝑎=10 N/𝑐𝑚2
,
Then 𝑙2is length which will be sufficient considering the allowable bearing strength
𝑙2 ≥
W
Bqa
Where B = 45.7+30 = 75.7 so take B=85
Get 𝑙2 ≥ 24.1

Chapter 4
72
So 𝑙2 ≥ 𝑙1 and for factor of safety of 2 get
L=50 cm
Secondly: depth of the embedment: h
If the assumed 𝑞 𝑎
,
(lateral bearing capacity) is 5 N/𝑐𝑚2
ℎ ≥
𝑊 tan 𝜃
𝑞 𝑎
,
𝐵
h ≥ 27.8 cm
For factor of safety of 2 get h=60 cm
Detail drawing for anchor
Figure4.23

Chapter 4
73
4.5.3.Curves Segments of Pipe
4.5.3. a. Elbow 90 o
- Thickness determination
𝒕 =
𝑷𝑫
𝟐[(
𝑺𝑬𝑾
𝑰 ) + 𝑷𝒀]
P =internal design gage pressure =70 bar
D =outside diameter of pipe as listed in tables of
standards or specifications or as measured. =18’’ Figure4.24
S = stress value for material =151.68 Mpa (from table A-1 in ASME B31.3).
E = quality factor =1 (from Table A-1A or A-1B in ASME 31.3)
W = weld joint strength reduction factor =1
R1=686 mm (from ASME.b16.9)
𝐼 =
4(
𝑅1
𝐷
)−1
4(
𝑅1
𝐷
)−2
=1.24989
Y = coefficient (from Table 304.1.1(in ASME B31.3), valid for t < D/6 and for
materials shown. The value of Y may be interpolated for intermediate
temperatures. For t ≥ D/6) =0.4
We calculate t= 12.888 mm≈13 mm
𝑡 𝑚 = 𝑡 + 𝑐
c =sum of the mechanical allowances (thread or groove depth) plus corrosion and
erosion allowances. For threaded components. =3mm
so tm=16 mm
- Check stresses for elbow By FEA
From solid works simulation

Chapter 4
74
Seq= 137.4 Mpa < 151.68 Mpa (safe)
Figure4.25
4.5.3.b. Elbow 45o
- Thickness determination
𝒕 =
𝑷𝑫
𝟐[(
𝑺𝑬𝑾
𝑰 ) + 𝑷𝒀]
P =internal design gage pressure =70 bar
D =outside diameter of pipe as listed in tables of standards or specifications or
as measured. =18’’
S = stress value for material =151.68 Mpa (from table A-1 in ASME B31.3).
E = quality factor =1 (from Table A-1A or A-1B in ASME 31.3)
W = weld joint strength reduction factor =1
R1=686 mm (from ASME.b16.9)
𝐼 =
4(
𝑅1
𝐷
)−1
4(
𝑅1
𝐷
)−2
=1.24989
Y = coefficient (from Table 304.1.1(in ASME B31.3), valid for t < D/6 and for
materials shown. The value of Y may be interpolated for intermediate
temperatures. For t ≥ D/6) =0.4

Chapter 4
75
We calculate t= 12.888 mm≈13 mm
𝑡 𝑚 = 𝑡 + 𝑐
c =sum of the mechanical allowances (thread or groove depth) plus corrosion
and erosion allowances. For threaded components. =3mm
so tm=16 mm
Hint the thickness will not change.
- Check stresses for elbow By FEA
From solid works simulation
Seq= 130 Mpa < 151.68 Mpa (safe)
Figure 4.26

Chapter 4
76
4.5.4. Soft soil
Piping settlement (δ):
δ = mv* ∆P*H (cm)
Where:
 Mv = volume change of soil
Or coefficient of volume compressibility
= 0.02 to 0.04 (cm2/N)
 ∆P = increased load , (N/cm2)
= Ia * ∆Wp
Where
 Ia = soil stress coefficient
= 0.3 to 1 ( dimensionless )
 ∆Wp = increased load , (N/m2)
 H = thickness of layer , (cm)
Figure4.27

Chapter 4
77
Calculations:
3. Weight of the excavated soil , W1
W1 = B * H * ȣsoil * Lpipe
W1 = 1.5*2.4572*1.2*1
W1 = 4.42296 (tonf)
W1 = 4.42296*9.81= 43.389 , (KN)
4. Weight of backfill soil , W2
W2 = (B*H – (∏/4 )*D0
2) * L * ȣsand *g
W2 = (1.5*2.4572 – (∏/4)*0.45722) * 1.2*1*9.81
W2 = 41.4565 , (KN)
5. Weight of pipes , W3
W3 = (∏/4) * (D0
2
- Di
2
) * L * ρ * g
W3 = (∏/4) * (0.45722
– 0.43182
) * 1 * 7850 * 9.81
W3 = 1.365727 , (KN)
6. Weight of kerosene in pipes , W4
W4 = (∏/4)* Di
2
* L * ρ * g
W4 =(∏/4)* 0.43182
*1 * 800 * 9.81
W4 = 1.149249 , (KN)
∆W = Increased load ( at face A )
∆W = W2 + W3 + W4 – W1
∆W = 41.4565 + 1.3657 + 1.1492 – 43.389
∆W = 582.4 , (N)
∆Wp = increased load pressure per unit area of the face (A)
∆Wp = ∆W/(L*B)
∆Wp = 582.4/(1*1.5*104
)
∆Wp = 0.3883 , (N/cm2
)
∆P = ∆Wp * Iσ

Chapter 4
78
The amount of settlement as follow:-
Between (A & B) ( δ1 )
δ1 = mv1 * ∆wp * Iσ1 * H1
δ1 = 0.036 * 0.3883 * 1 * 200
δ1 = 2.796 , (cm)
Between ( B & C ) (δ2 )
δ2 = mv2 * ∆wp * Iσ2 * H2
δ2 = 0.02 * 0.3883 * 0.7 * 324.28
δ2 = 1.763 , (cm)
Between ( C & D ) (δ3 )
δ3 = mv3 * ∆wp * Iσ3 * H3
δ3 = 0.5 * 10-3 * 0.3883 * 0.28 * 330
δ3 = 0.0179 , (cm)
Total settlement ( δtotal )
δtotal = δ1 + δ2 + δ3
δtotal = 2.796 + 1.763 + 0.0179
δtotal = 4.5769 , (cm )

Chapter 4
79
Deflection of pipeline:-
Figure 4.28
δ = L * tanθ
where :
δ = total deflection , ( m )
L = pipe length = 6 , (m )
Θ = deflection angle
Allowable degree of deflection per pipe = 30 ( push on joint )
δ allowable per pipe = 6 * 102 * tan(30)
= 31 , ( cm )
δ allowable per pipe ˃ δtotal ( safe )

Chapter 5
80
Chapter 5
Corrosion Protection
5.1. Introduction
Studying corrosion and its protection methods in pipeline systems is very important. As
corrosion causes very large economic losses.
Whether these losses are direct (cost of damaged parts) or indirect (stopping the production /
losses in product / over design considerations in thickness that costs useless money).
5.2. Overview
Corrosion has lots of types and shapes depend on the application.
Pipelines are exposed mainly to the following two types:
a) Chemical corrosion
It’s affected by the type of internal flow and outside conditions. So our project wouldn’t
be affected by this type as (kerosene) doesn’t react with (steel) of our pipe and most of
our line is underground.
b) Electrochemical corrosion
It’s our main effective one and it can cause losses in metal (steel) about (9.13 kg/year) if
corrosion current of (1 Amp) flows through the pipeline.
So we will explain briefly the concept, causes and protective methods we used to
protect the line.
Electrochemical corrosion concept
Firstly we should define the corrosion cell.
Corrosion cell is a condition on a metal surface where flow of electric current occurs between
two metal surfaces.
A corrosion cell consists of four fundamental components:
 Anode : higher potential voltage (+)
 Cathode : lower potential voltage (-)
 Electrolyte : Conducting environment for ionic movement)
 Electrical connection: between the anode and cathode for the flow of electron current.
Figure 5.1

Chapter 5
81
The driving force behind a corrosion cell is a potential or voltage difference between the anode
and cathode. It is important to know that each of the four elements of the corrosion cell affect
the severity of corrosion.
The following is a brief description of how this cell works.
Referring to Figure (5.2), a piece of zinc (Zn) and a piece of copper (Cu) are immersed in an
electrolyte, and the two metals (electrodes) are connected by a wire that is a good conductor
for electricity, such as copper.
From Table (5.3) above, zinc has higher electrical potential than copper. Consequently, a
current will flow from the copper to the zinc through the connecting wire. To complete the
electric circuit, a current of the same magnitude will flow through the electrolyte, from the zinc
to the copper.
This electrical current through the electrolyte removes molecules from the surface of the zinc
electrode, causing galvanic corrosion to the zinc.
Table 5.3 figure 5.2
In the project pipeline is iron so from the electrochemical series as shown we will know it’s
anode or cathode depending on the other metal in contact.
Figure 5.4

Chapter 5
82
 If the pipe is an anode it will be damaged (the problem)
 If the pipe is a cathode it will be protected (Cathodic Protection)
 If there was no electrical connection pipe will be protected (Coating)
5.3. Corrosion Control
Modern pipelines are protected from corrosion using CP techniques that include external pipe
coatings combined with impressed current or sacrificial anodes.
As a first step, the environment in which the pipeline is located must be investigated. This
includes soil to pipe potential measurements at various points along the length of the pipeline
as well as determination of the resistivity of the soil. Sometimes, just changing the environment
surrounding a pipeline, such as reducing moisture by improving drainage, can be a simple and
effective way to reduce corrosion.
Four common methods used to control corrosion on pipelines are protective coatings and
linings, cathodic protection, materials selection, and inhibitors.
5.4. Cathodic Protection (CP)
CP is a technique by which a buried pipeline is made as the cathode and another metal is used
as the anode that gets corroded by electro-chemical process instead of the pipe material.
as shown in this figure :
Figure 5.5

Chapter 5
83
The electric circuit requires a source of protective current. This is provided by either an active
(impressed current) or a passive (sacrificial) system of galvanic anodes (usually magnesium,
aluminum, or zinc).
A direct current (DC) system is used to counteract the normal external corrosion of a metal
pipeline resulting from the potential difference between the pipe and the soil.
Cathodic protection basically reduces the corrosion rate of a metallic structure by reducing its
corrosion potential, bringing the metal closer to an immune state.
The two main methods of achieving this goal are by either sacrificial anodes or the impressed
current method.
5.4.1. Sacrificial anodes: This involves connecting the pipe to a zinc or magnesium electrode
and the surrounding soil in a buried pipeline. This creates a galvanic cell shown in Fig (5.6)
in which the pipe becomes the cathode and the zinc or magnesium electrode becomes the
anode that gets corroded. Hence, the reason for the term sacrificial anodes.
Impressed current method: This method requires the use of an external DC source
(rectifier). The negative terminal of the rectifier is connected to the steel pipe and the
positive terminal is connected to the ground through an electrode. The pipe thus becomes
the cathode as shown in Fig. (5.7) When a copper sulfate electrode is used, the impressed
current rectifier is adjusted so that the pipe to soil potential is maintained at −0.85 V. This
potential should be maintained at various points along the pipeline.

Chapter 5
84
Figure 5.6
Figure 5.7

Chapter 5
85
5.5. Calculations
5.5.1. Design Parameters of Cathodic Protection (Impressed Current Method)
Pipeline diameter (m) 0.4572 m
Pipeline length (m) 260 × 103
m
Pipeline wall thickness (mm) 12.7 mm
Design life 25 years
pipeline coating 3 layer polyethylene
Design temperature 60℃
Current density for coated pipeline steel 15 mAmps/𝑚2
Current density at operating temperature
(60℃)
15 mAmps/𝑚2
Pipeline natural potential -500 mV
Minimum protective potential -850 mV
Coating resistance (PE coating) 20000 Ω.𝑚2
Steel resistivity 1.6 × 10−7
Ω.m
5.5.2. Design Formula:
The following formulae are used for the design of cathodic protection system:
Surface Area Sa=πDL (m2)
Protective current required
𝐈 =
𝑺 𝒂 ∗ 𝑪 𝒅
𝟏𝟎𝟎𝟎
Pipeline Linear Resistance: 𝒓 =
𝝆 𝒔
𝑨
Coating conductance
𝒈 =
𝝅𝑫
𝑹 𝒑
Attenuation constant: 𝒂 = √ 𝒓 ∗ 𝒈
Potential shift at drain point: 𝑬 𝒂 = 𝑬 𝒅𝒑 − 𝑬 𝒏
Potential shift at farthest Point : 𝑬 𝒇 − 𝑬 𝒏 = 𝑬 𝒎
Current Attenuation :
𝑳 =
𝟏
𝒂
∗ 𝐜𝐨𝐬𝐡−𝟏
(
𝑬 𝒂
𝑬 𝒎
)
𝑛𝑜 𝑜𝑓 𝑡𝑟𝑎𝑛𝑠𝑓𝑜𝑟𝑚𝑒𝑟𝑠
=
𝑳 𝒕𝒐𝒕
𝟐𝑳

Chapter 5
86
D = Diameter of pipe in meters
L = Length of pipe in meters
Sa = Surface area is m2
Cd = Current density in mAmps/ m2
W = Anode weight required for design life in Kg
Wa = Weight of proposed anode in Kg
Calculations
These calculations are used to get current attenuation L then no. of transformers
and their positions.
1- Surface Area
𝑆 𝑎 = 𝜋𝐷𝐿
𝑆 𝑎 = 𝜋 ∗ 0.4572 ∗ 260 ∗ 103
= 373447.4 𝑚2
2- Protective Current
I =
(1−𝑐𝑜𝑎𝑡𝑖𝑛𝑔 𝑒𝑓𝑓)∗𝑆 𝑎∗𝐶 𝑑
1000
(Coating efficiency =99%)
Cd=15mAmp/m2
I =
0.01∗373447.4∗15
1000
= 56 𝐴𝑚𝑝
3- Coating conductance
𝑔 =
𝜋𝐷
𝑅 𝑝
𝑔 =
𝜋∗0.4572
20000
= 7.18 ∗ 10−5
𝑚ℎ𝑜/𝑚
4- Cross Section Area of Pipeline
𝐴 𝑥𝑠 = 𝜋 ∗ 𝑡 ∗ (𝐷 − 𝑡)
𝐴 𝑥𝑠 = 𝜋 ∗ 0.0127 ∗ (0.4572 − 0.0127)

Chapter 5
87
𝐴 𝑥𝑠 = 0.0177 𝑚2
5- Pipeline Linear Resistance
𝑟 =
𝜌𝑠
𝐴 𝑥𝑠
𝑟 =
1.6 ∗ 10−7
0.0177
= 9 ∗ 10−6
Ω/𝑚
6- Attenuation Constant
𝑎 = √ 𝑟 ∗ 𝑔
𝑎 = √9 ∗ 10−6 ∗ 7.18 ∗ 10−5 = 2.542 ∗ 10−5
7- Potential Shift at drain point
𝐸 𝑎 = 𝐸 𝑑𝑝 − 𝐸 𝑛
𝐸 𝑎 = 1.2 − 0.5 = 0.7 𝑣𝑜𝑙𝑡
8- Potential shift at Length L
𝐸 𝑚 = 𝐸𝑓 − 𝐸 𝑛
𝐸 𝑚 = 0.85 − 0.5 = 0.35 𝑣𝑜𝑙𝑡
9- Length of pipeline protected from drain point
𝐿 =
1
𝑎
∗ cosh−1
(
𝐸 𝑎
𝐸 𝑚
)
𝐿 =
1
2.542 ∗ 10−5
∗ cosh−1
(
0.7
0.35
) = 51806.99 𝑚 = 51.8 𝑘𝑚
10- No of transformers
𝑛𝑜 𝑜𝑓 𝑡𝑟𝑎𝑛𝑠𝑓𝑜𝑟𝑚𝑒𝑟𝑠 =
260
2 ∗ 50
= 3 𝑇𝑅
So we will use 3 transformers rectifiers

Chapter 5
88
Selection of Anodes and transformers:
Anode:
Type: silicon Iron anode
Consumption: 0.5 Kg/Amp year
We need = 0.5*18.5=9.25 kg/year
= 9.25*25 ≈ 250 kg (life time =25)
No of anodes = 250/50 = 5 anodes/transformer (anode weight = 50 kg)
Total no of anodes = 5*3 = 15 anodes
Transformer: 25V/25 Amp
Anode
Silicon iron anode
Consumption: 0.5 kg/amp year
Weight : 50 kg
No : 15 anodes
Transformer 25V/25 Amp

Chapter 6
89
Chapter 6
Pressure Tests
6.1. Purpose
The purpose of these procedures is to ensure that pressure tests are conducted safely and
effectively. They cover pressure testing of new and existing pressure systems or components at
a test pressure, the main target of the pressure test to ensure the ability of piping system and
its components to meet the requirements of the applied pressure. Pressure testing has long
been used to determine and verify pipeline integrity. Several types of information can be
obtained through this verification process.
However, it is essential to identify the limits of the test process and obtainable results. There
are several types of flaws that can be detected by hydrostatic testing, such as:
 Existing flaws in the material,
 Stress Corrosion Cracking (SCC) and actual mechanical properties of the pipe,
 Active corrosion cells, and
6.2 Main types of pressure tests
There are two methods for pressure tests: hydrostatic and pneumatic.
A hydrostatic test: is performed by using water as the test medium. Pneumatic test: uses air,
nitrogen, or any non-flammable and non-toxic gas, Pneumatic tests are potentially more
dangerous than hydrostatic because of the higher level of potential energy. Pneumatic tests
may be performed only when at least one of the following conditions exists:
1-When pressure systems are so designed that they cannot be filled with water.
2-When test pressure is 10 percent of design pressure, generally for low pressure
application.
The used test pressure in the project would be the hydrostatic test using water as the
driven medium where the applied pressure not less than 1.25 times the internal
design pressure (ASME B31.4)
6.3. Hydrostatic Test main Procedures:
1- Obtaining test pressure after consulting the project engineer.
2- Completing pressure test plan and submits for approval.
3- Approving plan by Supervisor.
4- Ensuring the pressure gauges used have current calibration stickers.

Chapter 6
90
5- Removing all persons not directly involved with the test from the immediate test
area.
6- Removing pressure relief valves or non-reclosing relief device from the vessel or test
boundary where the test pressure will exceed the set pressure of the valve
Or Holds down each valve by means of an appropriate test clamp and pressurizes both
sides of non-reclosing relief devices Installs temporary, higher-rated devices where
practical.
7-Installing the calibrated test gauge so it is visible at all times.
8- Ensuring the skillet blanks or test plugs or clamps are appropriate for use and are free
of obvious defects.
9- Filling, removing vents system as necessary to remove as much air as practical.
10- Ensuring that water used for the test is at not less than ambient temperature, but in
no case less than 70°F.
11- Pressurizing the system, raising the pressure in the system gradually until the
designated test pressure is achieved.
12- Maintaining this test pressure for 10 minutes before inspection. Then, if test is
above maximum allowable working pressure (MAWP), reduces to MAWP while making a
full thorough inspection for leaks.
13- Ensuring the metal temperature at the time of the hydrostatic test does not exceed
120°F.
14- If there is evidence of structural distortion, either rejects the system or repairs as
advised by the inspector.
15- If there is leakage in the system, performs the following as appropriate:
A-Ensuring repairs is performed and returns to Step 12.
B-Rejecting the system.
16- When the test is completed, vents the test pressure to atmosphere and returns
relief devices to normal configuration.
6.4. Test sections
Generally, no pipeline test section shall include an aboveground portion more than 5%
of the total test section length to minimize the effect of temperature fluctuation due to
solar heating. The pressure test of each test section should commence as soon as
practicable after construction of the test section or assembly has been completed.
Within a certain test section, separate pre-hydrotest could be performed prior to
installation for the pipe string destined under crucial/strategic crossings such as, river or
navigation canals crossings, highways.

Chapter 6
91
Flow chart of the field hydrostatic test
Beginning of test
Decide on test section &test
pressure
Perform protective work at
each and of test section
Begin verification work on test
section
Install equipment required to
fill Pipeline
Fill pipeline with water
Install equipment required for
pressure test
Perform pressure test on
pipeline
Judgment
?
Not Good
Drain Pipeline
Remove test apparatus and
protective work from ends of
test section
Connect test section to
adjacent pipeline
Survey to locate defects
Drain Pipeline
Perform repair work
Good
Figure 6.1

Chapter 6
92
6.5. Test Equipment
Pump with flow meter suitable for the required
duty with pump rated 20% higher than the max.
test pressure, capable of driving pigs at the
required speed and pressure.
Filling Pumps
Volumetric pumps with variable speed equipped
with flow meter and rated at least 20% higher
than the max. test pressure
Pressurizing Pumps
Filters capable of back-flushing.Filters
To keep the pumps constantly on load.Manifolds and Break Tanks
For continuous injection of water treatment
packages and dye
Chemical Injection Pumps
Complete with the necessary gauges, recorders,
dead weight tester, barometer, …etc. so that the
test engineer can accurately assess the progress
of the hydrostatic test and record the pressure
and water volume conditions throughout the
tests
Test Cabin Unit
Measuring and recording continuously the flow
and the temperature of the filling water
Filling/Pressurizing flow meters
and temperature probe
Measuring and recording continuously the
pressure (24 hours)
Pressure recorders
With a range of 1°/+50°C, having 0.1°C accuracy
to be used on thermo-probes
Lab Thermometers
Measuring and recording Ambient air
temperature
Thermometers
Fitted to the pressuring pump and set at 3%
above the test pressure to assure that no over-
pressurization
Pressure Relief Valves
To release the pressure in a controlled manner
upon completion of the hydrostatic test.
Pressure Letdown Valves
For cleaning, gauging, filling and dewatering
operations
Test Heads
Various pigs for cleaning, gauging, filling and
dewatering operations.
Pigs
For locating the pig along the pipelinesPig Tracking Devices
For flushing by air (compressed air is to be oil-
free)
Air Compressor
With adequate flexible hoses for lines
dewatering.
Nitrogen Purging Skid

Chapter 6
93
Diagrammatic representation for the test
Figure 6.2
6.6. Requirements Prior To PRESSURIZING
Test heads and above-ground sections should be sheltered and thermally insulated in order to
minimize the effects of ambient temperature variations .
Pipe and soil temperature should be measured and recorded at each end of the test section
and if possible halfway along the test section
The test engineer shall carry out a plot of pressure/added volume using measurement of
volume added either by pump strokes or flow meter and instrument reading of pressure gauge
plus deadweight tester.
Projecting the elastic slope lines across the plot as shown allows the recording of pump strokes
and comparison of the evolving plot to those slopes. If and when the actual plot begins to
deviate from the elastic slope, either some pipe is beginning to yield or a leak has developed.
Figure 6.3

Chapter 6
94
The operator of the pressurizing equipment shall immediately report to the test engineer any
variation in the rate of pressure increase by the same volume of added water.
During pressurization, all potential leakage points shall be checked.
The rate of pressurization should be moderate and constant.
6.7. DURATION OF HYDROSTATIC TEST
The minimum duration for the hydrostatic pressure test shall be a 4-h strength test followed by
a 24-h leaktightness test.
6.8. PRESSURE HOLD PERIOD
The test pressure shall be held for a period of 24-hours during which the assembly testing shall
be visually examined and the following parameters shall be continuously recorded to assist with
the pressure/temperature variation calculation:
 Ambient temperature (every ½ hour).
 Water pressure and temperature (continuously and every ½ hour).
Barometric pressure
During the test, the pressure shall be recorded continuously, and the deadweight tester and air
temperature readings shall be recorded every 30 minutes.
The pipe and soil temperature shall be recorded at maximum 3-hour intervals.
6.9. STRENGTH TEST
If the test pressure is required to give a hoop stress of 96 % of SMYS based on minimum wall
thickness, it should be calculated as follows:
𝑇𝑝 =
2 𝑡 𝑚𝑖𝑛 𝑆𝑀𝑌𝑆 𝐹 𝐸 𝑇
𝐷 − 𝑡 𝑚𝑖𝑛

Chapter 6
95
Where:
𝑇𝑝 hydrostatic strength test pressure(g) (MPa)
𝑡 𝑚𝑖𝑛 specific minimum wall thickness of pipe (m)
𝐷 nominal outside diameter of pipe (m)
𝑆𝑀𝑌𝑆 Specified Minimum Yield Strength (SMYS)
(MPa)
F design factor (for hydrostatic strength test
F = 0.96)
E longitudinal joint factor
E = 1.0
T temperature derating factor
T = 1.0
6.10. LEAKTIGHTNESS TEST
The leak tightness test should commence immediately after the strength test has been
completed satisfactorily the leaktightness test pressure should be at least 1.1 times the internal
test pressure.
6.11. ACCEPTANCE of leaktightness test
The test shall be considered successful if no observable pressure loss occurs that cannot
be attributed to temperature fluctuations, taking into account the accuracy and
sensitivity of the measuring equipment. It should be noted that the pressure variation
due to temperature fluctuation is calculated as follows:
P/T = { - [2(1+) . ]} / [Di/(E.t) + (1/B)]
Where,
 : Coefficient of linear expansion
(For normal carbon steel = 1.17 x 10-5 °C-1 at normal temperature)
 : Volumetric expansion coefficient of test water
Di : Pipeline inside diameter
E : Young’s Modulus of Elasticity of pipeline material
(For carbon steel, E = 207 X 103 MPa)
t : Pipe wall thickness
 : Poisson’s ratio
(0.3 for steel)
B: Bulk Modulus of test water
6.12. Depressurization
After satisfactory completion of the hydrostatic test, the test section shall be depressurized to
atmospheric head plus 1 bar so that air does not enter into the test section. Pressure let-down

Chapter 6
96
valves shall be opened slowly and depressurizing continued at a rate that does not generate
vibrations in the associated pipework
6.13. Hydrostatic test for the project
Diameter=18 ‘’
Thickness=0.5’’
Test's section:
Hydro test will be carried out for both underground pipes and mountain before installation.
Since SMYS=359 Mpa
𝑇𝑃 =
2(𝑡 𝑚𝑖𝑛)𝑆𝑀𝑌𝑆 ∗ 𝐹𝐸𝑇
(𝐷 − 𝑡 𝑚𝑖𝑛)
And leaghtightness test pressure will be 1.1 of design pressure
The leaghtightness test pressure will be 77 Bar.
Therefore the strength test pressure will be 119 Bar.
It is recommended to reduce test pressure for less than these numbers for pipes in service in order not
to reduce the strength of the material

Chapter 6
97
6.14. Example for the strength test result graph
Figure 6.4

Chapter 6
98
6.15. Example for the leaghtightness test result graph
Figure 6.5

Chapter 6
99
6.16. Actual photo to Hydrostatic test
Figure 6.6

Chapter 7
100
Chapter 7
Pipeline Welding & NDT
7.1. General
The pipeline welding shall comply to API 1104, while the welding materials shall comply with
American Welding Society AWS 5.1 for carbon steel electrodes for Shielded Metal Arc Welding,
AWS 5.5 for low alloy steel electrodes for Shielded Metal Arc Welding, AWS 5.28 for low alloy
steel electrodes and rods for Gas Shielded Arc Welding, and AWS 5.29 for low alloy steel
electrodes for Flux Cored Arc Welding.
100% X-Ray inspection shall be adopted for on-site girth welds in case of manual and semi-
automatic welding, while golden welds and other critical welds (such as those on pipes under
major waterway/highway crossings) shall be 100% Radiographic and/or Ultrasonic inspected.
7.2. Welding Techniques
The most common pipeline welding techniques are given hereafter.
7.2.1. SMAW (shielded Metal Arc Welding)
Consumable electrode covered with metal sheath (Flux) that stabilizes, shields the arc
and melt pool from atmosphere contamination. The electrode can match the base
metal or be of any special alloy.
Advantages: Can weld most metals, thin or thick parts, suitable for all welding
positions, Equipment light and easily transportable, AC or DC power supply.
Disadvantages: Slag needs to be cleaned after each pass, tends to spatter the melt weld metal.
7.2.2. SAW (submerged arc welding)
Electrode itself or an additional welding rod could constitute the filler metal, arc is submerged
by the deposition of the melt flux, which shields the arc and melt pool from atmosphere
reducing the cooling rate.
Advantages high deposition rate and deep penetration, hence suitable for thick plates even
with imperfect alignment of bevels.
Disadvantages: welding equipment large. Mostly horizontal (flat) weld position, arc
immediately covered by flux (welder cannot see it), metal stays molten for long time due to flux
cover which may require backing.

Chapter 7
101
7.2.3. GMAW (Gas Metal Arc Welding)
Also called Metal Inert Gas Welding "MIG" when it is shielded by inert gas (Helium), and Metal
Active Gas Welding "MAG" when it is shielded by a reactive gas (C02) · Consumable electrode
fed through gas nozzle continuously supplying shielding gas (Helium, Argon, C02). Mostly for DC
power supply.
Advantages: slag free, can weld most materials, weld bead controllable by the shielding gas
Selection.
Disadvantages welding equipment large, liable to "electric shorts" which could lead to lack of
fusion, need for continuous gas source, not suitable for outdoors welding (since wind can blow
the gas away), tends to spatter the melt weld metal.
7.2.4. FCAW (Flux Core Arc Welding)
Consumable electrode that contains in its center either the flux which stabilizes, shields the arc
and melt pool from atmosphere contamination (self-shielding FCAW), Or alloy for which gas
shielding would be required (gas shielded FCAW)
Advantages Can weld most metals, suitable for all welding positions, high deposition rate, slag
is thin and can be readily removed.
Disadvantages: welding accompanied by smoke, need to chip-off flux at the end of each pass.
7.2.5. GTAW (Gas Tungsten Arc Welding)
Non-consumable electrode made in Tungsten contained in the center of the gas nozzle, welding
could be without filler metal or with a separate welding rod supplying filler metal. The arc and
weld pool are protected by inert gas (Argon or Helium). Suitable for root and hot passes (root)
on standard pipes.
Advantages: Good quality welds since electrode and welding rod are separately controlled,
spatter free (no weld clean-up), AC or DC power supply.
Disadvantages: slow process, shielding gases could be affected by wind.
7.3. Weld joint Design
The most suitable way of welding is: SMAW (Shielded Metal Arc Welding)
The selected Electrode is E6010 (according to API 1104)
The number E6010 indicates an arc welding electrode with a minimum stress relieved
tensile strength of 60,000 psi; is used in all positions.
The weld bead design AS follows:

Chapter 7
102
Figure 7.1
As long as the pipe nominal thickness = .5” < 7/8”, thus the joint should be plain
bevel Fig. (a)
Specific Dimensions As follows:-
Figure 7.2

Chapter 7
103
7.4.NDT
There are two methods of inspection to a welded pipe or other specimen:
- One is to subject the material or weld to destructive tests, which would provide information
about the performance of that test object. The disadvantage of Destructive testing is that, as
the name implies, the test object is destroyed in the process.
The other method is referred to as non-destructive tests because they permit
evaluation of the material or component without destroying it. Destructive
testing of parts can be expensive and assumes that the untested parts are of
the same quality as those tested. Non-destructive tests give indirect yet valid
results and, by definition, leave the test object fit for its intended use.
There are a variety of NDT methods that can be used to evaluate the completed welds. All
NDT methods share several common elements.
These elements are:
• some source of probing energy or some type of probing medium
• discontinuity that must cause a change or alteration of the probing medium
• Some means of detecting the change
• Some means of indicating the change
• Some means of observing and/or recording this indication so that an
interpretation can be made.
While there are many different methods of NDT only the more common NDT methods used for
the evaluation of welds in Oil field will be outlined here. These methods are the following:
(1) Visual inspection
(2) Ultrasonic testing
(3) Magnetic Particle Testing (MT)
(4) Radiographic inspection
(5) Liquid Penetrant Testing (PT)
(6) Electromagnetic Testing (ET)
(7) Acoustic Emission Testing (AE)
(8) Guided Wave Testing (GW)
(9) Laser Testing Methods (LM)
(10) Leak Testing (LT)
(11) Magnetic Flux Leakage (MFL)
(12) Neutron Radiographic Testing (NR)
(13) Thermal/Infrared Testing (IR)

Chapter 7
104
7.4.1. Visual Test
VT is considered to be the primary NDT method. Since it relies on an
evaluation made using the eye, VT is generally considered to be the primary and
oldest method of NDT. With its relative simplicity. It is a very inexpensive method
thus provides an advantage over other NDT methods. A further advantage of VT is
that it is an ongoing inspection that can be applied at various stages of
construction. VT can be improved by using aids such as a magnifying glass to
improve its effectiveness and scope.
VT requires three basic conditions to be in place. These are:
• Good vision, to be able to see what you are looking for.
• Good lighting, the correct type of light is important.
• Experience, to be able to recognize problems.
Advantages:
(a) Primary method of inspection
(b) Most economical inspection method
(c) Applicable at any stage of fabrication
Limitations
(a) Restricted to surface inspection
(b) Good eyesight required
(c) Good lighting required
7.4.2. Ultrasonic testing
Ultra-high frequency sound is introduced into the part being inspected
and if the sound hits a material with a different acoustic impedance (density
and acoustic velocity), some of the sound will reflect back to the sending unit
and can be presented on a visual display. By knowing the speed of the sound
through the part (the acoustic velocity) and the time required for the sound
to return to the sending unit, the distance to the reflector (the indication
with the different acoustic impedance) can be determined. The most
common sound frequencies used in UT are between 1.0 and 10.0 MHz, which
are too high to be heard and do not travel through air.
Sound is introduced into the part using an ultrasonic transducer ("probe") that
converts electrical impulses from the UT machine into sound waves, then
converts returning sound back into electric impulses that can be displayed as a
visual representation on a digital or LCD screen.

Petroleunm Pipeline Design (Graduation Project)

Petroleunm Pipeline Design (Graduation Project)

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