PETRONAS TECHNICAL STANDARDS DESIGN AND ENGINEERING PRACTICE
MANUAL
PIPELINES
PTS 20.180H DECEMBER 1991
PREFACE
PETRONAS Technical Standards (PTS) publications reflect the views, at the time of publication, of PETRONAS OPUs/Divisions. They are based on the experience acquired during the involvement with the design, construction, operation and maintenance of processing units and facilities. Where appropriate they are based on, or reference is made to, national and international standards and codes of practice. The objective is to set the recommended standard for good technical practice to be applied by PETRONAS' OPUs in oil and gas production facilities, refineries, gas processing plants, chemical plants, marketing facilities or any other such facility, and thereby to achieve maximum technical and economic benefit from standardisation. The information set forth in these publications is provided to users for their consideration and decision to implement. This is of particular importance where PTS may not cover every requirement or diversity of condition at each locality. The system of PTS is expected to be sufficiently flexible to allow individual operating units to adapt the information set forth in PTS to their own environment and requirements. When Contractors or Manufacturers/Suppliers use PTS they shall be solely responsible for the quality of work and the attainment of the required design and engineering standards. In particular, for those requirements not specifically covered, the Principal will expect them to follow those design and engineering practices which will achieve the same level of integrity as reflected in the PTS. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal or its technical advisor. The right to use PTS rests with three categories of users : 1) 2) 3)
PETRONAS and its affiliates. Other parties who are authorised to use PTS subject to appropriate contractual arrangements. Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) and 2) which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said users comply with the relevant standards.
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PREFACE TO THE PRODUCTION HANDBOOK, REVISION 1991 Objective The objective of the Production Handbook is to contribute to efficient performance by all Engineering, Petroleum Engineering and Operations staff, by providing quick access to and practical guidance on their own and related disciplines' technology. Being a comprehensive combination of condensed technical manuals, it provides a ready source of information for reference and self-training. It is not intended to replace detailed design manuals and state-of-the-art manuals; these should remain the first source of reference for more experienced technical specialists. Neither can the Production Handbook replace specialised training manuals. Distribution The Production Handbook should be available to all Engineering, Petroleum Engineering and Operations staff at or above JG5, in Group E&P Operating Companies and SIPM. These staff receive the Handbook as a personal loan; they may take it along when going on transfer within the Group but must return it when leaving for other reasons. Staff of other Functions' parentages temporarily working in E&P companies may use library copies. The Handbook is confidential and holders should note the conditions stated opposite the title page. Issue and recovery should be registered by company secretariats/libraries. Reprinting and updating The Production Handbook was first published by SIPM in 1986. It is the successor to the Field Pocketbook versions of 1933,1947, 1952 and 1955 and the Field Handbook of 1963. The 1986 version comprised 3000 pages in five AS ringbinders; 6000 copies were distributed. An update of some 250 revised pages was issued in 1987 and a list of further corrections was published in the Production Newsletter of November 1988. A complete reprint is necessary at this time (1991). For flexibility and cost-effectiveness this updated reprint is in nine paperback volumes, each one dedicated to a major discipline with clear ownership' by the SIPM-EP department concerned. These custodian' departments will initiate further updates of their respective volumes as and when necessary. Additional volumes and state-of-the-art manuals in the same format may be added later as special supplements. Suggestions for revising and updating the Handbook should be directed to the SIPM-EP custodian department of the respective volume, using copies of the Specimen Amendment Sheet at the back of each volume. Overall editorial custodianship of the Handbook rests with SIPM-EPD/1 1.
CONTENTS LIST PRODUCTION HANDBOOK SERIES (1991) SIPM Custodian Volume 1 Production General - Units and Conversion Factors - Health Safety and Environment - Quality Management - Economic Analysis
EPO/71 EPO/6 EPO/72 EPE/1
Volume 2 Drilling and Transport - Drilling - Civil Engineering for drilling locations - Transport in Production Operations
EPO/51
Volume 3 Petrophysical Engineering
EPD/22
Volume 4 Reservoir Engineering
EPD/22
Volume 5 Production Technology - Production Engineering - Production Chemistry
EPD/41
Volume 6 Production Operations
EPO/53
Volume 7 Process Engineering - Oil Processing - Gas Processing Custodian for Part I Ch. 7 Terminals:
EPD/42
Volume 8 Pipelines
EPD/61
Volume 9 Facilities and Maintenance - Running Equipment - Piping Systems - Electrical Engineering - Instrumentation Telecommunications - Reliability and Availability Assessment - Corrosion Engineering - Inspection Techniques and Maintenance Terminology - Diving and Underwater Operations - Air Conditioning
EPD/62 EPD/62 EPD/63 EPD/64 EPDI76 EPD/13-EPO/54 EPD/65 EP0154 EPO/54 MFSH/11
EPD/13
PREFACE TO VOLUME 8, PIPELINES, REVISION 1991 The subjects covered in this Volume were formerly included in the 1986 version of the Production Handbook as Chapter 10, Pipelines. The following former Sections have, however, been substantially condensed: - 1.3 - 3.5 - 3.6
External Corrosion Protection Pipeline Monitoring and Control Internal Corrosion and Corrosion Monitoring.
More detailed information about these subjects can be found in Volume 9.
VOLUME 8, PIPELINES, REVISION 1991 SUMMARY CONTENTS LISTING 1. Design 2. Construction 3. Operations 4. Pipeline Standards 5. Safety Requirements for Pipelines 6. Documentation 7. References and Further Reading
Volume 8
PIPELINES
CONTENTS 1
DESIGN
1.1
Hydraulics
1.1.1 1.1.2 1.1.3 1.1.4 1.1.5
Physical Properties General Energy Equation Fluid Flow through Pipelines Heat Transfer in Pipelines Pump and Compressor Power Requirements
1.2 Materials 1.2.1 Line Pipe 1.2.2 Pipeline Components 1.3 External Corrosion Protection 1.3.1 External Coatings: General 1.3.2 Coating Materials 1.3.3 Coating Inspection by Electrical Means 1.3.4 Field Joint Coatings 1.3.5 Storage of Coated Line Pipe 1.3.6 Cathodic Protection 1.3.7 Internal Coatings and Liners 1.4 1.4.1 1.4.2 1.4.3 1.4.4 1.45 1.4.6
Pipe Stability Introduction Calculation of the Required Submerged Weight Recommendations on Velocities and Coefficients Required Concrete Thickness Remarks and List of Symbols Application of Concrete Weight Coatings
1.5 Stresses and Loads 1.5.1 Codes 1.5.2 Collapse/Buckling in Offshore Pipelines 1.5.3 Pipe Loads in Conventional Laybarge Laying 1.5.4 Suspended Spans of Pipe Laying on Bottom 1.5.5 Buried Lines 1.5.6 Risers 1.6
Design Requirements for Internal Inspection Tools
2
CONSTRUCTION
2.1
Landline Construction
2.1.1 2.1.2 2.1.3 2.1.4 2.2 2.2.1 2.2.2 2.2.3
Codes and Permits Surveys, Landline Construction Construction General Special Construction Submarine Line Construction Survey Construction Submarine Protection
2.3 Field Welding and Inspection 2.3.1 Welding 2.3.2 Weld Inspection 2.3.3 Codes and Standards 2.3.4 Common Pipeline Welding Terms 2.4
Hydrostatic Testing
2.4.1 2.4.2 2.4.3 2.4.4 2.4.5
Testing Requirements Test Equipment and Instrumentation Determination of Residual Air Volume in Pipeline Hydrostatic Leak Test Evaluation Location of Leaks During Hydrostatic Testing
2.5
Cleaning/Drying/Pigging
2.5.1 2.5.2 2.5.3
Cleaning Drying Pigging
3
OPERATIONS
3.1 Commissioning 3.1.1 Liquid Product Pipelines 3.1.2 Gas Pipelines 3.2 Pipeline Monitoring and Control 3.2.1 Process and Instrument Diagram 3.2.2 Leak Detection 3.3 Internal Corrosion and Corrosion Monitoring 3.3.1 Internal Corrosion, General 3.3.2 Corrosion and Control at the Design Stage 3.3.3 Corrosion Monitoring 3.3.4 Dryness Monitoring 3.3.5 Corrosion Prevention Methods 3.4 Pipeline Inspection 3.4.1 Pipeline Failures 3.4.2 Pipeline Inspection and Monitoring Methods 3.4.3 Intelligent Pigs 3.5 Routine and Special Operations 3.5.1 Cleaning 3.5.2 Inhibition 3.5.3 Liquid Removal 3.5.4 Product Separation 3.6 Pipeline Repair 3.6.1 Safety 3.6.2 Emergency Procedures 3.6.3 Temporary Repair 3.6.4 Permanent Repair 4
PIPELINE STANDARDS
4.1
General
4.2 4.3
External Standards Group Standards
5
SAFETY REQUIREMENTS FOR PIPELINES
5.1 General 5.2 Onshore Pipelines 5.2.1 General 5.2.2 Liquid Pipelines 5.2.3 Gas and Liquefied Gas Pipelines 5.3
Offshore Pipelines
6
DOCUMENTATION
6.1
General
6.2 Engineering Stage 6.2.1 As-Built Reoords 6.2.2 Construction Report 6.3
Operations
7 REFERENCES AND FURTHER READING SPECIMEN AMENDMENT SHEET
TABLES Table 1.1-1
Compositional calculations
Table 1.1-2
Representative equivalent length in pipe diameters(Lid) of various valves and fittings
Table 1.1-3
Values of thermal conductivity, maximum allowable temperature
Table 1.2-1
Selection and typical valve application criteria
Table 1.2-2
Main dimensions and approximate mass of flanged ball valves reduced bore to API Specification 6D
Table 1.2-3
Main dimensions and approximate mass of flanged ball valves full bore to API Specification 6D
Table 1.2-4
Main dimensions and approximate mass of flanged gate valves to API Specification 6D
Table 1.2-5
Main dimensions and approximate mass of full bore flanged ball valves to BS 5351
Table 1.2-6
Main dimensions and approximate mass of reduced bore flanged ball valves to BS 5351
Table 1.2-7
Main dimensions and approximate mass of flanged globe valves to BS 1873
Table 1.3-1
Maximum stacking heights for coated pipe
Table 1.4-1
Recommended values for pipe stability calculations
Table 1.5-1
Stress levels allowed by ANSI B31.4 and B31.8
Table 1.5-2
Out-of-roundness function g(r, d)
Table 1.5-3a) Basic load conditions for single spans Table 1.5-3b) Combined load conditions for single span Table 1.5-4
One end deflection of a single span
Table 1.5-5
Global buckle length of single spans
Table 1.5-6
Uniformly loaded pipe resting on more than one support
Table 1.5-7
Natural frequencies single spans
Table 1.5-8
Values for Kb, Kz and If
Table 1.5-9
CD values for pipe in trenches as function of H/BD
Table 1.6-1
Pig trap lengths for internal inspection tools
Table 2.2-1
Multi-user positioning systems
Table 2.2-2
Tow methods for laying offshore pipelines
Table 2.4-1
Summary of methods for the location of leaks during hydrostatic testing
Table 2.5-1
Cleaning applications/methods
Table 2.5-2
Cleaning pigs
Table 2.5-3
Gauging pig and displacement/separation pigs(spheres)
Table 2.5-4
Swabbing/drying pigs
Table 3.2-1
Leak detection methods
Table 3.4-1
Types of commercially available intelligent pigs
FIGURES Figure 1.1-1
Approximate relative temperatures
density
of
hydrocarbon
fractions
at
different
Figure 1.1-2
Compressibility factors for natural gases
Figure 1.1-3a
Compressibility of low molar mass natural gases 1
Figure 1.1-3b
Compressibility of low molar mass natural gases 2
Figure 1.1-3c
Compressibility of low molar mass natural gases 5
Figure 1.1-4
Basic characteristics of Newtonian and non-Newtonian liquids
Figure 1.1-5
Kinematic viscosity vs. temperature, and other properties, for a wide range of traditional crude oils
Figure 1.1-6
Hydrocarbon gas viscosity
Figure 1.1-7
Approximate specific heat capacity ratios of hydrocarbon gases
Figure 1.1-8
Bernoulli's Theorem
Figure 1.1-9
Bernoulli's Theorem applied to one pipeline profile, e.g. for three different flow rates (q1< q2 < q3), shows the change in location of hmax and hmin, pump locations and end-pressures hd
Figure 1.1-10
Moody diagram
Figure 1.1-11
Oil-transmission lines head-loss curves for engineering design
Figure 1.1-12
Horizontal flow regimes
Figure 1.1-13
Generalised flow regime map for horizontal two-phase flow
Figure 1.1-14
Normalised friction factor curve (see Ref. 5)
Figure 1.1-15
Eaton liquid hold-up correlation (see Ref. 4)
Figure 1.1-16
Liquid bulk modulus K of liquid hydrocarbons
Figure 1.1-17
Pressure surge due to line packing
Figure 1.1-18
Effect of moisture content on thermal conductivity of sand and clay soils
Figure 1.2-1
Pressure/temperature rating to ANSI B 16.5/ANSI B 16.34
Figure 1.2-2
Pressure/temperature rating for ball valves designed to BS 5351
Figure 1.3-1
Typical sacrificial anode system
Figure 1.3-2
Typical impressed current system
Figure 1.4-1
Cross-section of pipe on sea bed
Figure 1.4-2
Required concrete thickness for stabilising gas-filled submarine pipelines
Figure 1.4-3
Submerged density of concrete coated pipe and correction for asphalt coat
Figure 1.4-4
Relation waveperiod-wavelength
Figure 1.4-5
Typical particle size distribution
Figure 1.4-6
Typical cube/core relationship
Figure 1.5-1
Collapse pressure Pc as a function of D/t and steel grade
Figure 1.5-2
Moment vs. curvature as a function of D/t ratio for API 5LX-42 pipe
Figure 1.5-3
Moment vs. curvature as a function of D/t ratio for API 5LX-60 pipe
Figure 1.5-4
Notations for analysing a 2-D suspended pipe span
Figure 1.5-5
Sag-bend minimum radius vs. height at the inflection point. To is the bottom
Figure 1.5-6
Bending strain vs. developed length of pipe span
Figure 1.5-7
Angle of pipe axis vs. height at the inflection point. To is the bottom tension
Figure 1.5-8
Dimensionless curves for depression spans
tension
Figure 1.5-9
Dimensionless curves for elevation spans
Figure 1.5-10
Example riser model
Figure 1.6-1
Scraper trap length consideration when using internal inspection tools
Figure 2.1-1
Typical excavation and backfill operations
Figure 2.1-2
Typical trench dimensions
Figure 2.1-3
Trench configurations
Figure 2.1-4
Field bend
Figure 2.1-5
Typical ditch and minor stream crossing
Figure 2.1-6
Typical cased railway crossing
Figure 2.1-7
Typical uncased road/rail crossing
Figure 2.1-8
Typical casing installation details
Figure 2.1-9
Typical cathodic protection and test cable connection
Figure 2.2-1
Pull tube method
Figure 2.2-2
Bending shoe method
Figure 2.2-3
Barefoot riser method
Figure 2.2-4
Typical clamp for anchoring riser at top of jacket
Figure 2.2-5
Typical clamp with limited degrees of freedom for adjustments
Figure 2.2-6
Typical clamp with complete freedom for adjustments
Figure 2.3-1
Nomogram for preheating requirements
Figure 2.4-1
Typical schematic of test section
Figure 2.4-2
Determination of residual air volume
Figure 2.4-3
Bulk modulus of fresh water as a function of pressure and temperature
Figure 2.4-4
Bulk modulus of sea water as a function of pressure and temperature
Figure 2.4-5
Volumetric expansion coefficient of fresh water as a function of pressure and temperature
Figure 2.4-6
Volumetric expansion coefficient of sea water as a function of pressure and temperature
Figure 2.5-1
Gel cleaning train
Figure 2.5-2
Diagram of a typical launching/receiving trap
Figure 3.2-1
Simplified process and instrument diagram
Figure 3.4-1
Performance of oil pipelines in Western Europe and in the North Sea
Figure 3.4-2
The 'Linalog' inspection tool
Figure 3.4-3
The Linalog record
Figure 3.4-4
Kaliper run record
Figure 3.4-5
Intensive cathodic protection inspection
1 DESIGN 1.1
Hydraulics
1.1.1
Physical Properties
1.1.1.1
Density of Liquids
Figure 1.1-1 shows the approximate relative density of petroleum fractions versus temperature.
1.1.1.2
Gases, Equation of State
The Equation of State (EOS) is required to describe gas properties in pipelines. For non-ideal gases, which will generally be encountered by the field engineer, the EOS is given by: pV = n z RT where: p = absolute pressure, Pa V = volume, m3 z R T n
= = = =
compressibility gas constant, 8314.3 J/(kmol . K) temperature, K number of kmols
The compressibility factor z can be read from Figure 1.1-2 using: - reduced temperature Tr = T/Tc - reduced pressure p r = p/pC Critical temperature Tc and critical pressure pC can be calculated as a weighted average of Tc and pC of the components of the mixture as outlined in1.1.1.5.
If the composition is unknown, the following empirical relationship can be used:
where: ρrel = relative density (air = 1) p = pressure, kPa. Relative density is defined as follows:
At standard conditions of 15ºC and 101.325 kPa, Zair = 0.9996 and ρair =1.2255 kg/m3
For natural gases with various molar mass values M the compressibility factor z can be read directly from Figures 1.1-3 a, b and c. The vapour density at specified temperature and pressure is expressed by:
It should be noted that the graphs are reasonably valid for gases containing less than 5 mol % non-hydrocarbons, e.g. CO2 , H2 S, N2 .
FIGURE 1.1-1 APPROXIMATE RELATIVE DENSITY OF HYDRACARBON FRACTIONS AT DIFFERENT TEMPERATURES
FIGURE 1.1-2 COMPRESSIBILITY FACTORS FOR NATURAL GASES
FIGURE 1.1-3A COMPRESSIBILITY OF LOW MOLAR MASS NATURAL GASES 1
FIGURE 1.1-3B COMPRESSIBILITY OF LOW MOLAR MASS NATURAL GASES 2
FIGURE 1.1-3C COMPRESSIBILITY OF LOW MOLAR MASS NATURAL GASES 3
1.1.1.3
Viscosity of Liquids
The viscosity characterises the fluidity of a liquid. Most crude oils are Newtonian, where the shear stress is directly proportional to the shear rate. Figure 1.1-4 shows the basic characteristics of Newtonian and non-Newtonian liquids. An example of a liquid with Bingham plastic behaviour is a waxy crude oil below its pour point..
Dynamic and kinematic viscosity are distinguished and interrelated as follows: µ
=
where: µ = ν
=
ν.ρ 3
3
dynamic viscosity, Pa.s = 10 cP = 10 mPa.s 6
6
kinematic viscosity, m2 /s = 10 cSt = 10 mm2 /s
Figure 1.1-5 shows, for illustrative purposes, the kinematic viscosity versus temperature for a wide range of traditional crude oils listed with their basic properties.
FIGURE 1.1-4 BASIC CHARACTERISTICS OF NEWTONIAN AND NON-NEWTONIAN LIQUIDS
FIGURE 1.1-5 KINEMATIC VISCOSITY VS TEMPERATURE, AND OTHER PROPERTIES, FOR A WIDE RANGE OF TRADITIONAL CRUDE OILS
The pressure dependence of liquid viscosity is given by:
where: p µ µo
= pressure, kPa (gauge) = viscosity, Pa.s = viscosity, Pa.s at atmospheric conditions (101.325 kpa)
1.1.1.4 Viscosity of Gases The viscosity of gases depends on temperature, relative density, and pressure (see Figure 1.1-6). Natural gases commonly encountered in field practice show Newtonian behaviour.
1.1.1.5
Compositional Calculations
The properties of a gas mixture can be calculated as the weighted average of the properties of the individual components of the mixture as shown in Table1.1-1.
Table 1.1-1 Compositional calculations
FIGURE 1.1-6 HYDROCARBON GAS VISCOSITY
The specific heat ratio as a function of gas mixture molar mass is given in Figure 1.1-7. Note:
Molar specific heat capacity cpm is temperature dependent. For example: at 0ºC: cpm = 38.3 kJ/(kmol . K) at 50ºC: cpm = 40.8 kJ/(kmol. K) (cp-temperature tables for the individual components can be found in Ref. 1)
1.1.2
General Energy Equation
The 'energy equation' for one-dimensional steady state flow through a pipeline is expressed by the law of conservation of energy and for incompressible fluid is given by Bernoulli's Theorem:
where: h(x) he hp
= total energy head at location x = elevation above datum = pressure head = p/ρg
hv
= velocity head = v2 /2g
hf
= friction loss head = f
L v2 d 2g
all expressed in metres of the pipeline fluid, and: d p
= internal diameter, m = pressure, Pa
ρ
= density liquid, kg/m3
g v f L
= acceleration due to gravity, m/s2 = velocity, m/s = friction factor = length of pipe between x = a and x = b, m
FIGURE 1.1-7 APPROXIMATE SPECIFIC HEAT CAPACITY RATIOS OF HYDROCARBON GASES
The Bernoulli Theorem is illustrated in Figure 1.1-8. Usually for liquid lines the velocity head is equal at the beginning and end of a pipeline and can therefore be omitted in head loss calculations.
FIGURE 1.1-8 BERNOULLI'S THEOREM
In pipeline design, Bernoulli's Theorem is used as shown in Figure 1.1-9. As a function of head loss gradient (and thus of the internal diameter d and flow rate q) the maximum head (hmax) at low points in the line can be found and also the minimum head (hmin) available to pass high points. Also the location of pump stations can be chosen and the Figure shows the pressure head at the end of the line (hd), which is important at the entry to a tank farm or a pump station. If too much energy (pressure) is left in the end of the line, pressure reduction may be required before entering a tank. If the required pressure drop is very large, a normal control valve may not be suitable, and a parallel set of low noise control valves or a set of parallel small diameter pipes may solve the problem. Note that Figure 1.1-9 can be seen not only as one pipeline with three different flow rates, but also as three pipelines with different internal diameters but one flow rate.
FIGURE 1.1-9 BERNOULLI'S THEOREM APPLIED TO ONE PIPELINE PROFILE
1.1.3
Fluid Flow through Pipelines
1.1.3.1
Pressure Loss Term
The pressure loss term in the general equation for a pipeline is given by:
where: ∆p = pressure loss, Pa f = friction factor, L = length, m d = internal diameter, m V = average flow velocity, mis ρ
= fluid density, kg/m3
1.1.3.2
Friction Factor
There are two factors in use, generally indicated by: f = Moody-Weissbach friction factor, which is the most universally used fn = Fanning friction factor The relationship is f = 4 fn The type of flow is characterised by the dimensionless Reynolds number and the friction factor is related to it i.e.
The types of flow are: 64 Re 2. Turbulent flow if Re > 3000: f can be calculated with the Colebrook-White equation, which relates f, Re and roughness of the pipe wall ε by:
1. Laminar flow if Re < 2000: f =
This equation can only be solved iteratively. Some values of ε are: Clean steel 0.02 mm Plastic coated 0.01 mm
Rusted steel Asbestos cement Concrete Coflexip
0.1 mm up to 1 mm for badly corroded pipe 0.03 < ε < 0.1 mm 0.2 < ε < 1 mm d/200 mm for flow in optimum direction
3. The remaining area between 2000
For gas flow which due to low viscosity virtually always has a very high Re number (> 10 ) the Colebrook-White equation simplifies to:
1.1.3.3 Pressure Loss in Liquid Lines Using volume flow as input instead of velocity, the general pressure loss equation transforms to:
where q = flow rate, m3 /s. The relation between head loss and volumetric flow rate is illustrated in Figure 1.1-11.
1.1.3.4
Pressure Loss in Valves and Fittings
These losses are determined experimentally and are expressed either by the resistance co&e&ffi&e&nt ζ which must be added to the loss for the main line (Ref. 2) or as equivalent length of pipe (Ref. 1), as shown in Table 1.1-2. The additional friction losses are only significant for short pipelines with many fittings such as pump and production station piping.
FIGURE 1.1-10 MOODY DIAGRAM
Table 1.1-2 Representative equivalent length in pipe diameters (L/d) of various valves and fittings
1.1.3.5
Pressure Loss in Gas Lines
For level gas lines containing no liquid, the AGA equation can be used to calculate pressure losses, as follows:
z p L T q d f
= = = = = = =
compressibility factor (see Figures 1.1-3a, b, c) pressure, MPa length, m flowing temperature, K flow, m3 /s (standard conditions: 15 ºC, 101.325 kpa) internal diameter, m friction factor
Note: When ρ is density of gas at standard conditions (101.325 kPa and 15ºC): -10 C = 5.7 x 10 Mpa/K If ρ is relative density compared to air (at standard conditions) C = 7.0 x 10
1.1.3.6
-10
MPa.kg/(K.m3 )
Two-Phase Flow in Pipelines
(a) General aspects For the field engineer, two-phase flow in pipelines mainly concerns oil and gas or condensate and gas systems, both often complicated by the presence of water and/or glycol/methanol. (i)
Important parameters For evaluating the behaviour of a pipeline operating in two-phase flow a number of important parameters must be considered, as follows: - Liquid volume fraction ( λ l ):the fraction of liquid present locally in the fluid; this is determined by the thermodynamic equilibrium between the two phases at the local pressure and temperature. - Liquid hold-up (Hl): the accumulation of liquid in the pipeline due to the difference in velocity (slip) between the phases and the influence of gravity (Hl > λ l ; Hg = 1 Hl). - Two-phase pressure loss: due to the presence of a second phase, pressure loss increases compared to single-phase flow.
-
Superficial velocity (vs ): the velocity which one phase would have if it was flowing through the total cross-sectional area of the pipe on its own.
-
Flow regime: the mode of flow in the pipeline which is an indication for the distribution of the liquids over the cross-sectional area (see Figure 1.1-12 for flow regimes and Figure 1.1-13 for a flow regime map).
-
Pipeline profile: representing the angle of inclination in every point of a pipeline; this profile influences the liquid hold-up, the flow regime and thereby the pressure loss.
(ii)
Slugcatchers Generally at the end of a two-phase flow gas/condensate pipeline a slugcatcher is required. This is a large container, generally designed to pipeline pressure, which has to handle large volumes of volatile liquids emerging from the line as slugs'. The slugs may be created by changing flow conditions in the line or by a pigging/sphering operation and will enter the slugcatcher at pipeline velocity (see 2.5, 3.5, 3.6). The slugcatcher should be designed such that if only liquid enters the slugcatcher the gas supply to the downstream facilities (gas plant, LNG plant, compressor station) is not interrupted.
FIGURE 1.1-12 HORIZONTAL FLOW REGIMES
FIGURE 1.1-13 GENERALISED FLOW REGIME MAP FOR HORIZONTAL TWO-PHASE FLOW
(b) Calculafion techniques (i) Empirical method Two-phase pressure loss and liquid hold-up cannot be reliably calculated with one of the many empirical correlations available from open literature. These have in general been derived by curve fitting data obtained from low pressure small scale experiments with air/water and ignore flow pattern and line profile. Using these correlations the results can vary from one method to another by a factor of 2-8.
(ii) The 'KSLA design method' The deficiencies of the published correlations have been overcome by the KSLA design method which has been largely developed from physical principles and has been verified by controlled flow tests in existing high pressure gas/condensate trunklines. This method is too complicated to reduce to a few handy equations or graphs. Its calculated method has been incorporated in the confidential Shell computer program available from SIPM.
(iii) Order of magnitude calculation Should order of magnitude calculations for peak flow conditions, i.e. for initial line sizing, have to be made without the benefit of the computer program, the 'AGA case II' correlation for pressure drop and the 'Eaton' correlation for liquid hold-up form the best combination. This method is not recommended for slugcatcher sizing or for reduced flow conditions, since the results are often conservative and could lead to oversizing. 'AGA-Case II' correlation for friction loss
FIGURE 1.1-14 NORMALISED FRICTION FACTOR CURVE (see Ref. 3)
A correlation has been developed for a normalised friction factor ftp/f vs. λ l and is shown in Figure 1.1-14. The friction factor f is obtained from:
Note:
The subscript tp denotes the two-phase equivalent for the parameter.
'Eaton' correlation for liquid hold-up Liquid hold-up is calculated using the following correlation:
where: vsl = superficial liquid velocity, m/s vsg = superficial gas velocity, m/s 3 ρ l = density liquid, kg/m 3
ρg
= density gas, kg/m
σl
= surface tension liquid, N/m
µl
= viscosity liquid, Pa.s
d p pb g
= = = =
pipe internal diameter, m actual pressure, kPa base pressure, = 101.325 kPa 2 acceleration due to gravity, m/s
This correlation is shown in Figure 1.1-15 Default values for surface tension: Crude-gas: 0.02-0.03 N/m Condensate-gas: 0.001-0.005 N/m Recommended sequence for simplified two-phase flow calculations: 1. Calculate liquid hold-up at known pipeline inlet conditions (pressure, liquid/gas densities). 2. Calculate pressure drop with parameters at inlet condition. 3. Determine average pressure (pin + pout)/2. 4. Calculate liquid hold-up at average pipeline pressure (revised liquid/gas densities).
FIGURE 1.1-15 EATON LIQUID HOLD-UP CORRELATION (see Ref. 4)
5. Calculate pressure drop with parameters at average pipeline pressure. 6. Repeat Steps 3, 4 and 5 till no significant difference in pressure drop compared to previous calculation occurs. 7. Calculate dimensionless numbers X, T, F and K (see Figure 1.1-13) and determine flow pattern (horizontal pipe line).
1.1.3.7 Pressure Surges Pressure surges in a pipeline are created by a change in momentum of the moving stream, e.g. by closing a valve, the origin of the pressure surge being at the point where the momentum of flow is changed. Because of the low density of gases compared to liquids, pressure surges are not of concern in gas lines. The theoretical maximum pressure surge that can be created in a pipeline would be caused by an instantaneous total blockage of the flow and would occur at the point of flow retardation, e.g. the valve. The maximum surge pressure is the sum of two components: (a) The instantaneous pressure increase at the moment of total flow blockage (b) The subsequent gradual pressure rise due to the 'line packing' effect. (a) The magnitude of the instantaneous surge can be calculated using Joukowsky's equation:
where: ps = surge pressure, Pa 3 ρ = liquid density, kg/m c = speed of sound in liquid, m/s (typically about 1200 m/s in crude) ∆v = velocity change, m/s c is calculated from:
where: K = liquid bulk modulus, Pa (see Figure 1.1-16) 9 E = Youngs modulus of steel, 210 x 10 Pa d = pipe internal diameter, m tw = pipewall thickness, m 3 ρ = liquid density, kg/m
FIGURE 1.1-16 LIQUID BULK MODULUS K OF LIQUID HYDROCARBONS
(b)
The pressure due to line packing at the point of closure will, if no protective measures are taken, continue to rise until the positive surge travelling upstream has reached the constant pressure end-point (e.g. a tank) and returned to the valve, i.e. during the time t = 2L , where L is the length of the pipeline section in metres. c The pressure rise due to the line packing effect can be calculated from Figure 1.1-17. FIGURE 1.1-17 PRESSURE SURGE DUE TO LINE PACKING
Small quantities of entrained gas in a liquid will drastically reduce K and consequently c (from typically 1200 m/s to 100 m/s) thereby reducing the magnitude of the maximum surge pressure pS . If a potentially critical surge problem does exist, then a more thorough surge analysis should be performed by modelling the pipeline using a transient pressure simulation program, e.g. EPSURGE.
Methods of reducing surge pressures The primary method of preventing the generation of unacceptably high surge pressures should be the implementation and strict adherence to well formulated and clearly written operating procedures. Additional measures which may be employed to reduce surge pressures are as follows; 1. 'Slow' valve closure By closing a valve over a sufficiently long period the surge generated may be significantly reduced. This also allows more time to trip the pumps and hence reduce the maximum pressure. This can be implemented either by slowing down the valve actuator or by installing a two speed actuator which reduces the valve closure speed over the (critical) last 10-20% of the valve's travel. 2. Installing a pressure relief system If the creation of an unacceptable pressure surge cannot be avoided using option 1, a pressure relief system can be installed as near to the point of surge origin as practically possible. The system would vent a quantity of product from the pipeline once a pre-set pressure limit is exceeded thereby limiting the final surge pressure. This can be implemented using bursting discs or rapid response relief valves. 3. Initiating a pump trip If the advent of a potentially dangerous pressure surge is detected early enough, the tripping of the upstream pumps will generate a negative pressure wave which propagates from the pumps to the origin of the surge and can counter the positive pressure surge. The effectiveness of this form of surge protection depends on factors such as the pipeline length, amount of line packing, etc. Calculation example Calculate the total pressure surge created in a 20 km pipeline due to an instantaneous valve closure, where; 5 Inlet pressure = 50 x 10 Pa 5 Outlet pressure = 40 x 10 Pa 3 Liquid density = 800 kg/m Speed of sound in liquid = 1000 m/s Steady state liquid velocity = 1 m/s (a) Instantaneous surge
(b) Duration tLp of line packing after valve closure is:
From Figure 1.1-17 if tr = 2.5, then pr = 2.1. Total surge pressure above steady state pressure prior to start of valve closure:
1.1.3.8
Waxy Crudes
A waxy crude contains paraffins, which crystallise when the temperature gets too low for them to stay dissolved. Generally the crystals are of a plate or needle type and will interlock forming a three-dimensional network trapping the remaining fluid. This wax structure has a certain mechanical strength, causing problems in pipeline operation. The severity of the problems depends on: -
Crude oil • composition, e.g. wax content, distribution • thermal history, e.g. heating/cooling effects • mechanical history, e.g. shearing effects.
-
Pipeline • dimensions, e.g. diameter, length • operation, e.g. pressure, shut-in time • conditions, e.g. temperature, flow rate.
The problems are: - wax deposition • gradual loss of capacity • blockage -
solidification • arrest of flow • restart problems.
A crude oil may exhibit wax deposition when the pipeline operating temperature drops below the cloud point of the crude oil; solidification problems may arise below the pour point (see 0 Figure 1.1-5). The pour point is generally 10 to 40 C below the cloud point. Contrary to a physical property such as the melting point of a pure substance, the pour point of a waxy crude is often strongly dependent on its thermal history. 1. Wax deposition During flow through a pipeline the crude oil generally cools down, starting near the pipe wall where the temperature is the lowest. Wax crystals will be formed throughout the oil, but those in a small layer near the wall may adhere and build up a deposit. Deposited wax can be removed: - mechanically, e.g. scrapers, pigging - thermally, e.g. steam/electrical heating - by dilution, e.g. (hot) oil flushing - by chemicals, e.g. surfactants (effect is dubious). The build-up of wax deposits can be reduced by: - dilution (results in lower wax content) - optimal operating conditions, e.g. temperature and turbulence - additives, e.g. Shellswim. 2. Flow behaviour At temperatures above the onset of wax crystallisation, the waxy crude will, like many liquids, have a viscosity independent of flow velocity or more precisely shear rate. This is Newtonian behaviour. By contrast, a waxy crude will start to exhibit non-Newtonian behaviour at some temperature below the onset of wax crystallisation. This behaviour is characterised by a shear rate dependent upon viscosity and also a yield strength at zero velocity, both properties being strongly dependent on temperature. The increase in a waxy crude's viscosity at lower temperatures is greater than that which would be expected from a crude with a more conventional (ASTM) viscosity-temperature relationship. 3. Solidification If flow is interrupted, the crude cools statically, forming a gel with mechanical strength. When the available shear force in the pipeline cannot overcome the yield stress, it will be impossible to restore flow through the line.
where: ιA ∆p d L
=yield stress of crude, Pa = available pumping pressure, Pa = internal diameter, m = length, m
Possible solutions are: - Increase shear force • increase ∆p, e.g. booster pumps • decrease L, e.g. shorter sections -
Reduce yield stress • dilute with less waxy oil • heating/insulation of pipeline • additives, e.g. Shellswim.
- Core flow (oil flow surrounded by a water annulus) To obtain reliable procedures for handling and transport of such crude oils detailed laboratory tests are required.
1.1.3.9
Drag Reduction
When the capacity of a crude pipeline system has to be increased this is generally accomplished by either installing parallel pipes along those sections which form a bottleneck and/or more pump power. Sometimes an attractive alternative can be the injection of a friction reducing additive or 'drag reducer'. This is a high molecular weight polymer with a very long chain molecule. The effect of a drag reducer is based on the suppression of energy dissipating eddies which normally develop near the pipewall. Drag reducers therefore function only in fully developed turbulent flow. The drag reducing effect slowly decreases in the direction of flow due to a gradual breakdown of the long chain molecule. At booster stations with centrifugal pumps the dissolved polymer is fully destroyed and for further downstream effect fresh additive needs to be injected. Positive displacement pumps can be expe9ted to be far less damaging to the dissolved polymer. The drag reducer by its nature is an extremely viscous liquid and must be injected downstream of the main pipeline pumps with a small positive displacement pump. A pressurised nitrogen blanket is normally applied over the drag reducer supply vessel so as to achieve the net positive suction head required by the injection pump. The effectiveness of the drag reducer and the quantities required can be calculated from known polymer and crude oil data but predictions are at present not always very reliable. A first indication of quantities required is given below:
3
4-10 g/m for 5% capacity increase 3 8-25 g/m for 10% capacity increase 3 13-40 g/m for 15% capacity increase The drag reducer is usually more effective at high flow rates (say over 1.8 m/s) and low viscosities (less then 10 cSt) and short pipe sections (less than 75 km). The effectiveness will decrease with increasing water cut since the drag reducer is only soluble in the oil phase. Drag reducers are ineffective with waxy crudes at temperatures below their pour point. Shell has built up a considerable knowledge of drag reduction in pipelines and in view of the above it is recommended that the laboratory be contacted first to carry out preliminary experiments with a representative crude oil sample followed by a full scale trial, if the first indications are promising.
1.1.4 Heat Transfer in Pipelines When liquids have to be transported at relatively high temperatures, e.g. viscous crudes/products, temperatures and cooling rates can be determined using the following formulae: 1.1.4.1
where: Tx Ts T0 x y
where: cp = q = ρ = d =
Cooling Under Flow
= average temperature in cross-section of pipeline at distance x, K = soil temperature at pipeline depth, K = temperature in pipeline inlet (x = o), K = distance, m = characteristic heat transfer length (is the length over which temperature difference is reduced by 63%) and given by:
specific heat capacity of line contents, J/(kg K) 3 flow rate, m /s 3 liquid density, kg/m internal diameter, m
A reasonable approach for the convective heat transfer coefficient is given by: For turbulent flow:
and for laminar flow:
where: λ liq
v ν g γ
= liquid thermal conductivity, W/(m.K) = = = =
average liquid velocity, m/s liquid kinematic viscosity, m2/s acceleration due to gravity = 9.8 m/s2 thermal expansion coefficient, K-1 (for crude oil γ ≈ 8 x 10-4 K-1)
µ b = bulk liquid viscosity, Pa.s µw
Tb Tw
= liquid viscosity at wall temperature, Pa.s = bulk temperature, K = wall temperature, K
A general expression for the heat transfer coefficient of a specific layer can be written as:
where: λ layer
Dl dl
= thermal conductivity of the layer (steel wall, coating, insulation) (see Table 1.1-3 for typical values), W/(m.K) = outside diameter of layer, m = inside diameter of layer, m
The heat transfer coefficient to the environment for buried pipelines is given by:
where: h = burial depth pipe axis, m D0 = outer diameter of outermost layer, m The thermal conductivity of the soil can be found from Figure 1.1-18 which shows values of λ vs. moisture content of soil. Table 1.1-3 Values of thermal conductivity, maximum allowable temperature
FIGURE 1.1-18 EFFECT OF MOISTURE CONTENT ON THERMAL CONDUCTIVITY OF SAND AND CLAY SOILS
1.1.4.2 Stationary Cooling
where: Ts = ambient soil temperature at pipeline depth, K Tt, T0 = oil temperature at time t and 0 respectively, k λt
F
= dimensionless Fourier number =
λ ρ cp d t β
= thermal conductivity of liquid, W/(m.K) 3 = density llquid, kg/m = specific heat capacity liquid, J/(kg.K) = internal diameter, m = time, s = empirical coefficient (ranges from 6 to 10, depending on heat transfer in the soil round the pipe, the pipe coating, pour point of the liquid and wax layer on pipe wall. A higher value of β means higher thermal conductivity of these layers.
ρ cp D2
1.1.4.3 Specific Heat Capacity The specific heat capacity of crude oil is dependent on the temperature and can be approximated using the equation:
where: cp(T) = specific heat capacity at temperature T, J/(kg.K) T = temperature, ºC 3 ρ(T) = density at temperature T, kg/m
1.1.4.4 Insulation In some cases it may be required to insulate pipelines and piping in order to: -
retain heat, e.g. in heated crude avoid shrinkage of gas in above-ground lines protect personnel keep refrigerated lines cool prevent condensation (hydrocarbons and water) in gas lines prevent hydrate formation.
Some generally applied insulation materials are: - rockwool mats - polyurethane foam (PUF), closed cell - syntactic tillers (composite of epoxy and hollow glass microspheres) - "Plasticell" foam (high density PVC foam). To protect against water ingress and mechanical damage these materials are usually provided with an outer jacket and field joints made up of halfshells. It should be ensured that the line temperature is not too high for the chosen insulation material. Problems encountered with insulated lines are: - water ingress causing loss of insulation capacity - difficulty in leak detection - corrosion protection needing extra care - condensation between the cooled pipe and the insulation material in the case of refrigerant lines.
1.1.4.5 Heating Systems In some cases it is necessary to operate a heating system on a pipeline, e.g. to transport viscous crude or products, or waxy crude or low pour point products. The following systems can be used: - Steam tracing or electrical tracing. These methods can only be used on very short lengths, e.g. up to 2-3km, and usually they are confined to plant piping. - Skin effect current tracing (SECT). This is an electrical system and can be used for longer lengths. The maximum distance from a power point is approx. 25 km. - Heaters. These can be used to heat the crude/product at the beginning of the line and, if necessary, at intermediate points. For most heating applications there are alternative methods, e.g.: - Dilution with a less viscous crude, also transportation via the core flow method may be an alternative. - A waxy crude can be treated with a pour point reducing additive, e.g. Shellswim. Diluting with kerosine may also be a viable alternative.
1.1.5 Pump and Compressor Power Requirements For quick reference in pipeline calculations some formulae are given below. (For more detailed information, see Volume 9.) 1.1.5.1 Pumps
where: P q ∆p η
= power requirement, kW 3 = throughput, m /s = differential pressure, kPa = pump efficiency
1.1.5.2 Compressors
P pd ps q Tin z ρ rel
= = = = = = =
power requirement, kW discharge pressure, kPa suction pressure, kPa 3 throughput, m (st)/s input temperature, K compressibility factor (see Figures 1.1-2 and 1.1-3) relative density (air = 1)
η
= compressor efficiency
Outlet temperature:
0
Note that the maximum allowable outlet temperature per stage is 150 C (423 K). The following assumptions may be useful for calculations: - η = 0.75 = overall compressor efficiency - for intercoolers assume 100 kPa pressure loss - for suction/discharge piping assume 70 kPa pressure loss each. For turbine driven compressors the power requirement has to be increased to allow for fouling, wear, elevation and ambient temperature (see Vol. 9). For calculation of the fuel consumption of a compressor station in a long gas line the following first approximation can be used:
where: F Pturbine NHV
Psupport
3
= fuel consumption of the compressor and support functions, m (st)/hr. = average turbine power requirement, kW. 3 3 = nett heating value of gas, MJ/m (st), e.g. natural gas ≈ 41 MJ/ m (st), depending on composition 3 Groningen gas ≈ 35 MJ/m (st) (at 14.5 mol % N2) = power consumption (kW) of support functions associated with the compressor station, which includes electricity, lubricating oil system, cooling, etc. This figure depends strongly on climatic conditions, and on the extent of gas sourced power used for related activities.
1.2
Materials (See also 'Corrosion Engineering' in Volume 9.)
1.2.1 Line Pipe 1.2.1.1
Steel Pipelines
(a) Types and Grades of Pipe Due to the combination of strength, toughness, weldability and price the vast majority of trunk-lines and flowlines are constructed from carbon-manganese steel pipe manufactured and tested in accordance with API Spec 5L specifications for line pipe. For pipelines, only pipe manufactured by the seamless, electric weld, (ERW/ EIW) longitudinal submerged arc weld (SAW) and spiral SAW routes are considered. Grades available are: Grade B (240 MPa, 35,000 psi yield strength) and the grades X42 (290 MPa, 42,000 psi yield strength) through X46, X52, X60, X65 to X70. Lower grade pipe, up to grade X52, generally obtains adequate strength from normalised carbon manganese steels. For grades X52 and upwards in-creased strength requires either additions of other strengthening elements (niobium/vanadium), special rolling techniques (controlled rolling) or quenching and tempering. Satisfactory Group experience has been obtained up to grades X70, with the majority of trunk-lines in X52 and X60 grades.
(b) Pipe Sizes The international nomenclature - Diameter Nominal - written as D n (50, 80, 100, etc.) has been used for size of pipe, flange, valve etc. throughout this Handbook; the values indicate a nominal size in mm; the inch sizes have also been retained and are shown in brackets. Full size and thickness ranges can be found in the relevant API specification. The total ranges quoted are not universally available and pipe manufacturers offer a range of diameters, wall thickness (WT) and grade combinations dependent on the production route and specific pipe mill capabilities. Common sizes are shown below:
For the combination of extremes of dia./WT/grade the above manufacturing ranges will be limited in source.
(c) Selection With reference to the pipe production routes, traditionally ERW and spiral pipe had a higher risk of undetected defects being present and they were therefore not used in critical applications. However improvements have been made by some manufacturers in the ERW process and it is now more widely used. (The Shell approved pipe is called HFI welded pipe, from the improved welding process using "high frequency induction"). In general the use of cold-expanded pipe is recommended. Cold expansion promotes pipe roundness, it may reveal weld defects and can redistribute residual stresses after welding in a favourable manner.
(d) Additional Requirements (i)General Each pipe manufacturing route has specific features which must be covered with regard to inspection and testing to ensure a satisfactory product fit for installation and service. To this extent SIPM have developed supplementary specification requirements and conducted mill evaluations to assess the overall quality control and inspection capabilities of each mill. Even when using standard API and SIPM specifications it should be recognised that for certain pipelines additional considerations are essential with respect to: - corrosion and operating modes - toughness - weldability, etc.
(ii) Internal Corrosion (see also 3.3) When selecting materials the overall operating mode of the lines should be considered. In general the application of a corrosion allowance as a sate-guard against corrosion is not considered to be effective for larger pipelines. For sour service, NACE MR-01-75 gives limits of sour conditions and materials suitably resistant to sulphide stress cracking. For pipelines, it is recommended that resistance to hydrogen induced cracking is also specified. If it is required to operate the lines wet, and if there is significant CO2 present (which is often the case), then the overall aggressive nature of the contents can result in excessive corrosion. In these cases consideration of inhibition, drying, or use of special stainless steels should be given. The effect of CO2 partial pressure and temperature on weight loss corrosion of carbon steels is shown in a nomogram in 'Corrosion Engineering' in Vol.9. For two-phase or multi-phase lines the corrosivity of entrained water, its partition and the effect of dissolved CO2/H2S will require detailed review and analysis. It is recommended that the advice of an experienced corrosion engineer is sought when designing for such lines. (iii) Toughness For gas and two-phase gas/condensate lines the pipe material should have sufficient inherent toughness to resist fracture propagation. Two possible modes of fracture exist, i.e. brittle (cleavage) and ductile (shear). By specifying a Drop Weight Tear Test (DWTT) at a temperature lower than the minimum operating temperature (see API Spec 5L SR6) propagation of brittle fractures can be avoided. Even with fully ductile material it is possible to have long propagating fractures in high pressure gas lines. For this to occur, the basic material toughness is only one parameter, the others being type and pressure of gas, diameter and wall thickness, backfill conditions, etc. For conventional steels, it has been shown that by selecting material with a sufficiently high, fully ductile 'Charpy' energy, arrest of propagation can be achieved. Several empirical relationships have been derived from full-scale tests with methane to predict the propagation behaviour. For rich gas or two-phase lines operating at higher pressures these relationships are not valid and may be non-conservative. In certain cases it may be impossible to arrest a fracture by pipeline material selection alone and alternative mechanical crack arrestors may be required. For offshore lines these have often taken the form of modified buckle arrestors which have been used throughout the length of the line.
For vent or flare lines the minimum temperature during venting must first be established. Such lines normally operate under low pressure conditions (typically < 2 or 3 bar); consequently insufficient stored energy is available for propagating fractures. It is however, necessary that the pipe body, seam weld, and girth welds possess a minimum 'Charpy' thoughness to avoid initiation of brittle fracture at the low temperatures under external contraction stresses.
(iv) Weldability Section 2.3 covers field welding of pipelines. A measure of weldability can be expressed by the carbon equivalent (C.E.) formula:
(All elements in formula as % weight.) Materials with C.E.'s below 0.45 can be readily welded with limited heat treatment requirements. For low heat-input welding, e.g. mechanised CO2 welding, some difficulties can be experienced in achieving hardness requirements for sour service (RC22 or HV248). Where it is compatible with strength requirements, then by selecting progressively lower C.E. steels, excessive heat treatment requirements may be minimised.
1.2.1.2
Non-Metallic Materials
For certain projects, conditions may allow selection of alternative pipeline systems such as: - glass fibre reinforced epoxy (GRE) - internally coated pipe - internal lining (PE/cement) These all have limitations on type of fluid, pressure, temperature, etc. The relevant standards should be consulted for design and installation aspects (see 4 Pipeline Standards). 1.2.1.3
Quality Control
Attention should be paid to quality control aspects during the entire materials procurement phase. In the various codes and standards, requirements are given for chemical analysis, destructive and non-destructive testing, pressure testing, dimensional checks, etc.
Apart from witnessing such tests at appropriate moments due care should be given to a proper system for recording and documentation. In addition to specifying the quality measurements required the supplier should be required to operate a quality assurance system (see Volume 1) to provide the internal control needed to achieve quality consistently.
1.2.2 Pipeline Components 1.2.2.1 Valves (a) General A great variety of valve types is commercially available. For reasons of economy, interchangeability and minimum stock, the utilisation of different types of valves shall be kept to a minimum and, if possible, to standard types only. To define the actual purpose of a valve, the following descriptions shall be adhered to: Block valves Open or closed; e.g. to stop the flow, with minimum restrictions and pressure loss when open; e.g. - Ball valves - Gate valves Throttling valves Throttling service; e.g. regulation of the fluid, continuous or in various steps between closed and open limits of the valve; e.g. - Globe valves - Needle valves Check valves Back flow prevention; e.g. reverse flow must be stopped if the upstream pressure drops below static head or back pressure. Relief valves Overpressure control; e.g. to safeguard a system against excess pressure e.g. Safety relief valves. (b) Standards Important valve Standards and Codes: API Spec 6D Pipeline valves, etc.
BS 1414 BS 5351 BS 5352 ANSI B 16.34
Steel wedge gate valves Steel ball valves 1 Steel wedge gate, globe and check valves Dn 50 ) and smaller Valves. Flanged and buttwelded ends.
(c) Selection of Valves Valve selection is of major importance, both from necessity to obtain trouble-free operation of the pipeline system and from the point of view of the overall economics involved. An incorrect choice can cause serious trouble; sometimes involving major changeover from initial selection. For a proper selection of type and design of valve the guidelines mentioned in Table 1.2-1 may be used. The valves to API Spec 6D follow the pressure/temperature rating to ANSI B 16.5 and ANSI B 16.34 up to a 0 maximum temperature of 120 C (see Figure 1.2-1). The pressure/temperature seat ratings for ball valves to BS 5351 are shown in Figure 1.2-2. Note: Submarine Valves Many problems have been experienced with the applications of valves subsea. As a result submarine valves and actuators are the subject fit an extensive evaluation programme. At present the best solution would appear to avoid their use under water wherever possible. If this cannot be done it is recommended that advice be obtained from Central Offices on the selection of suitable valves.
(d) Selection of Valve Construction Materials For the pressure containing parts, only forged or cast steel is allowed. The selection of materials for internal components of valves is sensitive to the type of service. The advice of an experienced corrosion engineer should be sought.
(e) Valve Dimensions and Weights The dimensions and weights in Tables 1.2.-2 to 7 have been compiled to enable the determination of the space required for installing valves, as well as to help select the means of transporting them to the site. The dimensions shown in the Tables are the largest found in a number of representative manufacturers' catalogues, except for the face-to-face dimensions 'A' which are based on the applicable code as mentioned in the relevant tables. The weights are based on an average of those given in the catalogues. 1
) See 1.2.1.1 b
Table 1.2-1 Selection and typical valve application criteria
FIGURE 1.2-1 PRESSURE/TEMPERATURE RATING TO ANSI B 16.5/ANSI B 16.34
FIGURE 1.2-2 PRESSURE/TEMPERATURE SEAT RATING FOR BALL VALVES DESIGNED TO BS 5351
Table 1.2-2 Main dimensions and approximate mass of flanged ball valves reduced bore to API specification 6d
Table 1.2-3 Main dimensions and approximate mass of flanged ball valves full bore to API specification 6d
Table 1.2-4 Main dimensions and approximate mass of flanged gate valves to API specification 6d
Table 1.2-5 Main dimensions and approximate mass of full bore flanged ball valves to BS 5351
Table 1.2-6 Main dimensions and approximate mass of reduced bore flanged ball valves to BS 5351
Table 1.2-7 Main dimensions and approximate mass of flanged globe valves to BS 1873
1.2.2.2 Flanges All flanges up to and inclusive D n 600 (24 in.) used in pipelines shall be according to ANSI 16.5 (latest issue). For sizes above Dn 600 (24 in.) the flanges shall be in accordance with MSS-SP-44 (MSS - Manufacturers Standardisation Society-USA, latest issue). The pressure/temperature limitations of the flanges including the larger sizes according to MSS-SP-44 shall be according to ANSI B 16.5. For graphic representation of the flange ratings see Figure 1.2-1. The flanges shall be provided either with a raised face or with a ring joint face. Raised face flanges shall have a contact surface, suitable for the type of gasket to be used, i.e.: - For CAF (compressed asbestos fibre) gaskets; 'Serrated spiral finish', i.e. surface roughness of approximately RA 12.5 (µm). - For spiral wound gaskets: 'Smooth finish', i.e. surface roughness between RA 3.2 and RA 6.3 to ANSI B 46.1. - Ring joint flanges shall be provided with a groove type and surface finish as specified in ANSI B 16.5.
1.2.2.3 Fittings (Tees, Elbows, Reducers, etc.) Fittings, used in pipelines shall be fully in accordance with the requirements as laid down in ANSI B 16.9 and MSS SP-75. Mitered bends shall not be used. For product pipeline systems the use of buttwelded components from forged or cast steel is recommended. Threaded or socket welded connections are in general not suitable.
1.2.2.4 Pressure Drop in Pipeline Components Pressure drop due to pipeline components, e.g. valves and fittings, shall be expressed as equivalent length and added to the straight pipeline. (For values of equivalent length of valves and fittings see 1.1.3.4.)
1.3
Corrosion Protection
This Section gives a brief overview of external corrosion protection(see Volume 9 for more detailed information). Internal corrosion aspects are covered in Section 3.3.
1.3.1 External Coatings: General The most effective method of mitigating corrosion of the external surface of a buried or submerged pipeline is by the dual system of a coating, supplemented by a cathodic protection system which covers any damaged or deteriorated area of the coating. Coating technology is rapidly developing and many protective coatings are now available for pipeline use. For each specific pipeline system the selection is based on the specific corrosion problems to be encountered, and upon economics. The performance of any particular coating system is directly related to the conditions encountered during the transport and storage of the pipes, their installation and the operational life of the pipeline system, e.g. type of transport (rail, barge, etc.), duration and conditions of storage, pipeline terrain, operational temperatures, backfill and soil conditions. Therefore, before any pipeline coating selection is initiated it is imperative that the environmental and construction conditions of the pipeline are well understood. A coating system, with known and identified characteristics can then be matched to the need of a specific project. The main factors influencing the final coating performance are: adhesion, cohesion, flexibility, electrical resistance, moisture absorption, impact resistance, cold flow resistance, cathodic disbonding resistance, chemical and physical stability, ease of application and weathering resistance. Before applying a protective coating it is essential to ensure that the surface of the pipe is free from rust, millscale, moisture, grease, loose dust or any other incompatible material. The most efficient method for producing a perfectly clean surface is blastcleaning preferably executed in a plant or coating yard. Hand cleaning (wire brushing, needle guns, etc.) is labour intensive and is therefore almost exclusively used for small areas or where access is difficult, including repair of damaged coatings. For all methods of surface preparation, priming and coating should be carried out at the earliest opportunity to avoid contamination and/or re-rusting.
Some pipeline coatings require special application equipment, thereby limiting the coating to a plant or coating yard. Flexible coating materials can also be applied at the job site to the welded-up pipeline just before it is lowered into the ditch, the so-called over-the-ditch application. Although this method has been applied extensively, its use is no longer favoured due to limitations of pipe cleaning and quality control. The selection and purchase of yard applied coatings is therefore highly advisable.
1.3.2 Coating Materials The most important coatings which are available for the external protection of oil and gas transmission pipeline systems are: -
Hot applied asphalt or coaltar enamels Polyethylene coatings (PE) Fusion bonded epoxy coatings (FBE) Plastic tape wrappings Asphalt mastic coatings Cold applied epoxy coaltar coatings.
All the above systems are well known and have been used for many years, while some coatings (PE and FBE) are being developed further today to make full use of new formulae and application methods, in order to improve protection performance and to reduce costs. There are temperature limits for application of each of these coating systems which need to be taken into account in the choice of coating.
1.3.3 Coating Inspection by Electrical Means Pipeline protective coatings should be thoroughly inspected for 'holidays' (holes) both after the coating is applied and before the pipes are finally buried, or before weight coating is applied for offshore installation. Visual inspection will detect major coating damage areas but minor coating flaws require electrical inspection for complete holiday detection. Electrical inspection entails applying an electrical voltage across the coating with a so-called 'holiday-detector' whereby arcs to the pipe will occur at coating flaws. Required voltage for adequate holiday detection varies with coating thickness and type of coating material.
1.3.4 Field Joint Coatings With yard applied coatings, the coating of the field joints where the pipes have been welded into a pipeline should be carefully selected, and applied with sufficient overlap to ensure that the whole length of the pipeline is correctly protected. For the protection of joints, a variety of suitable coverings are available. The most commonly used systems are: -
polyethylene shrink sleeves epoxy field joint coatings (for FBE coated pipes) fused polyethylene powder (for PE coated pipes) cold applied tapes.
It is recommended practice to develop application procedures, which should contain acceptance criteria, and to use specially trained crews for installation for each specific job requirement. The preferred method for the protection of the weld joints of submarine pipes, protected with an asphaltic bitumen coating and provided with a concrete weight coating, is the application of a self-adhesive cold applied tape wrap around the weld joint followed by pouring hot asphalt mastic into a metal mould fitted around the weld area. When the mastic is applied the pouring procedure and temperature must be carefully selected such that occurrence of holes or porosity is avoided. The tape or wrap must be resistant to the temperatures that sometimes occur during the application of the mastic. As an alternative to mastic, PUF may be applied in combination with a cold tape or shrink sleeve wrapping.
1.3.5 Storage of Coated Line Pipe Line pipe should be stored free from the ground. Stacked pipes should be protected from ground surfaces and against movements by using suitable soft non-metallic materials. If pipe is stacked on sand dykes (stone-free), then strong plastic sheeting should be used to cover the sand dykes completely. All bearing surfaces should be carefully levelled to provide a uniform load distribution. To prevent flattening or damage to the coating the stacking height must be limited. The maximum stacking height must in principle be advised by the manufacturer.
If this information is not available Table 1.3-1 gives an indication of the maximum stacking height. Table 1.3-1 Maximum stacking heights for coated pipe
Because of the variations in concrete coatings, no generally applicable maximum stacking height for this type of coating can be advised.
1.3.6 Cathodic Protection 1.3.6.1 General Corrosion is an electrochemical reaction of a metal or alloy with its environment that results in degradation of the metal or alloy. Some parts of the metal(s) tend to become positively charged (anodic) and other parts negatively charged (cathodic). At the anodic areas the metal normally dissolves and corrosion occurs. This can be eliminated by bringing anodic and cathodic areas artificially to approximately the same potential. This technique is called cathodic protection (CP). In general a CP system consists of an anode through which, or by which, positive electric current is passed via the electrolyte, e.g. water, to the cathode (pipe to be protected). There are basically two different methods of cathodic protection: (a) Sacrificial anode system (b) Impressed current system
1.3.6.2 Sacrificial Anode System The anode (Figure 1.3-1) must be a less noble metal than the structure to be protected, capable of dissolving slowly and supplying the current for the structure to be protected. The major advantage of this system is that the current control is fully automatic. FIGURE 1.3-1 TYPICAL SACRIFICIAL ANODE SYSTEM
1.3.6.3 Impressed Current System In an impressed current system (Figure 1.3-2) there is an external direct current source (usually a transformer/rectifier unit fed from an AC supply main). FIGURE 1.3-2 TYPICAL IMPRESSED CURRENT SYSTEM
It no AC current is available the power required may also be obtained from diesel, thermal or solar generators. The direct current is discharged by 'inert' anodes. Typical anode materials (and their applications) are platinised titanium/niobium (sea water); graphite, silicon/iron, magnetite (soil or water); lead/silver (water). Operation of an impressed current system requires specialised supervision. Particular care should be taken to ensure correct connection of cables to pipeline and anodes as reversal of the connecting cables can result in accelerated corrosion of the pipeline. This has occurred in the past when insufficient attention was given to proper connection of the cables.
1.3.6.4
Buried Onshore Pipelines
Whenever pipelines are to be buried, cathodic protection should be considered as an anti-corrosion measure supplementary to the provision of a protective coating. The prerequisite for successful cathodic protection is a continuous electrolyte between the current source and the area to be protected. In areas with a low or varying water table, such as may be the case where the climate causes infrequent but heavy rainfall, the effectiveness of cathodic protection may be reduced. in such cases frequent inspection/monitoring is essential. The corrosion history of other pipelines or steel structures in the neighbourhood will often indicate the degree of corrosion to be expected, but a soil survey may be necessary to provide sufficient data for a rational installation design. The cathodic protection scheme should be conceived at the pipeline design stage, and should not beadded as an afterthought when the pipeline has been completed. The system should be capable of operation immediately following construction of the pipeline.
1.3.6.5
Offshore Pipelines
The low and uniform resistivity of sea water simplifies design of protection systems for submarine pipelines. Sacrificial anodes placed in the form of bracelets around the pipe are the preferred method. The use of impressed-current systems on offshore pipelines is not usually employed.
For protection of submarine pipelines by sacrificial anodes the latter are normally applied as 'bracelets' at intervals along a new line. Zinc is the standard bracelet anode material. Regular inspection is hampered by the difficulty in contacting the pipe metal underwater. Despite a number of surveying techniques being available there is no one technique which is completely satisfactory as each has its inherent disadvantages. The preferred method is diver or ROV assisted direct potential reading by the trailing wire method. (Also refer NACE RP-06-75, Control of Corrosion on Offshore Steel Pipelines.)
1.3.7 Internal Coatings and Liners Internal coating of pipelines can provide a physical barrier between the steel and the product being transported and this has been used as an internal corrosion prevention measure against corrosive products. The internal coating of gas and oil transmission pipelines as an internal corrosion prevention measure has only been used infrequently, because of the risk of flaking off during depressurisation. Moreover other corrosion mitigation measures are available which in most cases eliminate or reduce to acceptable levels the risk of internal corrosion such as: dehydration of the gas, the removal of liquid or solid contaminants by pigging, and the use of inhibitors. Nevertheless, internal coating may be considered where it is not feasible or economical to employ other corrosion control measures, such as in small diameter gathering lines or lines where corrosion cannot be adequately controlled with scraping, inhibitors, etc. Long distance natural gas transmission lines are often provided with an epoxy paint layer to reduce friction and/or to improve pipe internal cleanliness. Epoxy-coated pipe is sometimes also used in finished oil product lines to improve flow characteristics and maintain product quality or cleanliness. Internal coating with epoxies can be accomplished joint by joint at a coating plant or by coating entire line segments insitu. Plant application has the disadvantage that uncoated pipe remains at circumferential field-welded joints necessitating special techniques/procedures to cover the internal uncoated cutback areas to maintain internal coating integrity. This is only necessary if the coating is required for internal corrosion prevention. If the internal coating is required only to reduce friction and or improve pipe cleanliness, coating of the internal field joint area is not necessary.
In-situ coating is accomplished by passing a paint slug, contained between two pigs, through the clean and dry pipe segment. The internal pipe surface is cleaned and etched with a suitable acid solution, rinsed and then dried. This procedure enables coating of the entire internal pipe surface. Although internal inspection of the pipeline is virtually impossible over its entire internal surface, camera pigs have been developed to allow the assessment of internal pipeline surface condition by means of video or photographs. Experience with such tools is so far limited. An alternative internal corrosion protection. method is the insertion of a Poly-Ethylene (PE) inner pipe (liner) into the carbon steel outer pipe. The PE-liner system is considered to be proven technology for the onshore transportation of corrosive water. For hydrocarbon service (oil and gas) the system is very encouraging, but still involves some risks concerning liner collapse. The application is limited by certain chemicals, such as aromatics. The system can be designed to operate at high pressures (> 35 MPa), but the temperatures have to be limited to 65 degrees C. For more information refer to status report EP-89-1260.
1.4 Pipe Stability 1.4.1
Introduction
A pipeline resting on the sea bed is subjected to forces resulting from steady currents and waves. To ensure that these forces do not cause the line to be displaced, a concrete weight coating usually has to be applied (see Figure1.4-1). FIGURE 1.4-1 CROSS-SECTION ON PIPE ON SEA BED
The minimum coating thickness can be determined from the minimum required submerged weight calculated as shown below. For gas-filled pipe it can also be determined as a function of pipe diameter from the graphs shown in Figure 1.4-2. Having determined the ratio concrete thickness/pipe diameter, the graphs in Figure 1.4-3 enable the submerged weight per metre coated pipe to be estimated.
1.4.2 Calculation of the Required Submerged Weight The symbols used in the calculations described in 1.4.2 to 1.4.4 are defined in1.4.5.
1.4.2.1 Active and Reactive Forces Working on Pipe
1.4.2.2 Wave Induced and Steady Current Velocity The water velocity, as used here, represents the horizontal velocity component perpendicular to the pipeline caused by steady current, waves or both combined. The wave induced velocity is defined by:
For bottom stability purposes the significant wave height, e.g. of the once per hundred year storm, is used to determine the maximum of the wave induced velocity at pipe level which the pipeline has to survive. This maximum is given by:
(see also Figure 1.4-4)
The steady current effect at pipe level is given by:
This formula assumes a velocity profile with fully developed velocity vent at 1.5 m from the bottom. The total velocity at pipe level is:
To determine the wavelength as a function of the waveperiod, formula (4) or Figure 1.4-4 can be used.
1.4.2.3 Equilibrium Equation If the pipe is in equilibrium:
The maximum of equation (7) gives the minimum required submerged weight for lateral stability of the pipeline. When the pipeline is laid on a slope with angle (α), this maximum has to be increased to:
1.4.3 Recommendations on Velocities and Coefficients 1.4.3.1 Velocities Gas-filled pipe: The steady current velocity should be the maximum expected in 100 years ( v ºst ). The wave induced velocity amplitude should be derived from the significant wave height of the once per 100 year storm ( v wi ). Oil-filled pipe: During laying period: For the air-filled line on the bottom the steady current velocity should be the maximum expected in 1 year ( v ºst ), the wave induced velocity should be derived from the maximum significant wave height in the heaviest storm expected to occur in one year ( v wi ).
For the period of operation: The steady current velocity and the wave induced velocity should be derived as for gas-filled pipe, but in calculating the required concrete thickness the weight of the line-fill should be taken into account.
1.4.3.2
Coefficients
Table 1.4-1 gives the coefficients recommended for use in the formulae of 1.4.2. Table 1.4-1 Recommended values for pipe stability calculations
1)These values for CD and CL are in principle only valid for diameters below Dn 300(12 in.) or for velocities above 2 m/s. For larger diameters or lower velocities CD and CL vary with the Keulegan-Carpenter number (KC = vtot T/D0) and may be considerably higher. In that case the advice of specialists is required, although the above values can give a sensitivity check for calculation purposes. 2)The recommended value for the friction is for general use. In specific cases it may be required to determine the friction of the soil by friction tests, e.g. for liquefied clay soils (f) may be considerably lower.
1.4.4 Required Concrete Thickness The required thickness of the concrete coating can also be determined from Figure 1.4-2, which is valid for the following conditions: 1. 2. 3. 4. 5.
Pipeline is laid on a horizontal bottom Pipeline is only filled with gas Pipeline is continuously supported on the bottom Friction factor against lateral sliding (f) is 1.0 The forces induced by the current are evaluated following Morison's equation using for the different cases the coefficients from Table 1.4-1 and a waveperiod (T) of 10 s.
FIGURE 1.4-2 REQUIRED CONCRETE THICKNESS FOR STABILISING GASFILLED SUBMARINE PIPELINES
Continued next page
FIGURE 1.4-3 SUBMERGED DENSITY OF CONCRETE COATED PIPE AND CORRECTION FOR ASPHALT COAT (continued next page)
FIGURE 1.4-4 RELATION WAVEPERIOD-WAVELENGTH
6. For the evaluation of the concrete thickness no allowance for corrosion coating has been made. If coating is required see Figure 1.4-3. 3 7. Density of steel = 7850 kg/m 3 Density of sea water = 1030 kg/m Water absorption of concrete = 3% of concrete mass Mass of steel reinforcement = 5%
1.4.5
Remarks and List of Symbols
(a) In addition to the horizontal stability the vertical stability of the pipeline must also be considered. Some silty soils may have a tendency to liquefy causing the pipeline to sink or float depending on the density of pipe and liquefied soil. (b) If for technical or economic reasons the weight coating cannot be made sufficiently thick or heavy to stabilise the pipeline against the ocean forces, burying the line in a trench or anchoring (e.g. concrete saddles) should be considered. The symbols used in the above calculations (1.4.1 to 1.4.4) are as follows:
1.4.6 Application of Concrete Weight Coatings 1.4.6.1 General Concrete weight coatings are normally applied to offshore pipelines, river crossings and marsh lines to maintain the lateral and vertical stability of the pipeline. The amount of concrete is determined by the calculated required submerged weight of the pipeline, also called negative buoyancy. Most frequently the concrete is applied by the impingement method over an anticorrosion coating of asphalt or coaltar enamel. This design has demonstrated good short-term and long-term characteristics. Combined with properly selected tensioners on a laybarge this design has also been successfully installed offshore in many areas. Application methods for concrete coatings other than by impingement are being developed to resolve problems resulting from weight coating application over FBE anti-corrosion coating. Current experience with these applications is limited.
1.4.6.2
General Impingement Concrete Coating
The horizontal or vertical impingement process is generally used for concrete weight coating of pipelines. The concrete has a low water-cement ratio (typically 0.3 by weight) and well proportioned aggregates (see Figure 1.4-5). It is recommended that concrete pressure strength is determined from cores or cubes taken at random from the coated pipes. If cube strength is used as the acceptance criterion, then regular checks shall be made of the cube/core strength ratio. A typical cube/core relationship is illustrated in Figure 1.4-6 for vertically impinged heavy duty concrete.
FIGURE 1.4-5 TYPICAL PARTICLE SIZE DISTRIBUTION
FIGURE 1.4-6 TYPICAL CUBE/CORE RELATIONSHIP
The concrete coring process proposed by the contractor should be tested before production starts. It should not permit moisture loss for a period of seven days unless it can be demonstrated that there is no effect on the concrete quality. Good quality control is required to ensure consistent product quality. A well controlled coating plant will supply pipe with a calculated submerged weight not exceeding ± 10% of any joint and ± 2% on any day's operation. Water absorption of the concrete should be checked at least weekly. It is important that there is no metallic contact between the reinforcement and the pipe wall, since this would lead to cathodic protection problems. Normal duty concrete The recommended minimum concrete core strength at 28 days is 25 MPa(3,500 psi). The reinforcement may consist of one or more layers of wire mesh. Heavy duty concrete The recommended minimum concrete strength at 28 days is 35 MPa (5,000 psi). A reinforcement of wire mesh or rebar is recommended with a total reinforcement crosssectional area of 0.5% of the total area. Should the pipeline be subjected to severe bending during installation, e.g. by laybarge, the increased stiffness of the pipeline may require a special design of the reinforcement and slotting of the concrete to maintain a controlled stress distribution in the steel.
1.4.6.3 Concrete Poured On Site River crossings and short loading lines have been installed with concrete poured on site. Because of the generally lower density of the concrete the cost of formwork and the time required on site for preparation and curing this method is generally not competitive with an impingement coating plant. The recommended minimum concrete core strength at 28 days is 25 MPa. Reinforcement should preferably be steel although also non-conventional materials such as polypropylene rope have been used successfully.
1.4.6.4 Special Coatings Development continues of new concrete coatings which can be applied by methods other than impingement or pouring. Technically some processes are showing potential, e.g. compression coating. Commercially they are as yet unproven. Technical advice should be sought for these coatings.
1.5 1.5.1
Stresses and Loads Codes
Generally, allowable stress levels are governed by local or national Codes of safe practice for pipelines. When no such regulations exist it is recommended that ANSI Codes B31.4 (Liquid Petroleum Transportation Piping Systems) and B31 .8 (Gas Transmission and Distribution Piping Systems) are followed. An interpretation of the stress levels in the pipeline allowed by these Codes is shown in Table 1.5-1. Distinction is made between buried and above-ground lines mainly in recognition of different reactions to weight, pressure (internal and external), thermal and pressure expansion and/or external forces such as wind, current etc. To judge situations not specified in the Codes it is recommended that the equivalent stress in accordance with the von Mises criterion should be used:
For the symbols used see Table 1.5-1. Codes often consider different load conditions separately. In some cases this results in the Code allowing stress conditions which when combined in accordance with the von Mises criterion will exceed 1.0 Sy As an example B31.4 allows a longitudinal (bending) stress SI < 0.75 x 0.72 Sy (unrestrained lines) and a hoop stress Sc < 0.72 Sy Ignoring shear stresses von Mises concludes that the equivalent tensile stress Seq = 1.095 Sy This example illustrates that BS1.4 can be interpreted unconservatively For compressor station piping BS1.8 recommends type C construction (a usage factor α = 0.5) but for pump stations B31.4 makes no special provisions except those for unrestrained lines. The Code for pressure piping in chemical plants and petroleum refining installations, ANSI B31.3, is usually much more conservative in allowable stress levels than B31.4 and B31.8. One of the main reasons is that B31.3 is usually applied to relatively small diameter piping, covering both steel and other material in unburied condition, with hazard conditions typical for fired petroleum plants. In offshore applications, risers to production platforms often require special analysis of stress conditions due to functional loads (pressure, weight, expansion, prestressing) and to additional environmental loads (wind, waves current, accidental loads).
The DnV 'Rules for Submarine Pipeline Systems' (1981) specify for risers and pipelines on or within 500 m from platforms a usage factor α, which reduces the allowable stress level to: α = 0.5 for functional loads α = 0.67 for functional + environmental loads. By comparison the DnV usage factor for pipelines located more than 500 m away from a platform is: α = 0.72 for functional loads α = 0.96 for functional + environmental loads. Fatigue is not normally a significant load condition for pipelines, the main exception being offshore lines, where laying, wave actions on suspended spans etc. require design based on detailed analysis of all relevant factors. The fatigue life can be assessed using appropriate S-N (stress range versus number of cycles) curves and Miner's 'cumulative damage rule'. Finally it should be noted that the use of the codes should be in agreement with sound design practice.
Note: Care should be taken to avoid anomalies at specification breaks. For example the internal diameters of pipes to B31.3 (Chemical Plant and Petroleum Refinery Piping) and to B31.8 will be different for the same service. Consistent internal diameters are needed if internal inspection tools are to be passed through the pipeline.
Table 1.5-1 Stress levels allowed by ANSI B31.4 and B31.8 (continued next page)
1.5.2
Collapse/Buckling in Offshore Pipelines
1.5.2.1 Collapse of Round Straight Pipe
and collapse occurs if the overpressure p approaches pc. The relation between pc and D/t is shown in Figure 1.5-1.
FIGURE 1.5-1 COLLAPSE PRESSURE pc AS A FUNCTION OF D/t AND STEEL GRADE
1.5.2.2
Collapse of Initially Oval Pipe
Ovality reduces the collapse pressure ( p * ) of the pipe to a level defined by:
where:
and the out-of-roundness function
Table 1.5-2 gives values of g(r, d) for various steel grades, ovalities.
D t
ratio and common ranges of
Table 1.5-2 Out-of-roundness function g(r, d)
1.5.2.3 Collapse Pressure and Axial Load Axial forces will affect collapse resistance. For pipe under external (over) pressure (p) and tension (+T) or compression (-T) the following expression can be derived:
The formula is based on the assessment of the equivalent stress of combined longitudinal and hoop stress in accordance with the von Mises criterion, in which the shear stress is assumed small enough to be neglected. The factor 1.15 = 2/3 √3 stems from the influence of external pressure (over-pressure) on longitudinal stress. The formula tends to indicate that:
1.5.2.4 Bending - Buckling of Straight Initially Round Pipe For undamaged line pipe, critical bending strain ε o reached when the bending parameter:
has reached a maximum value:
where: D = outer pipe diameter t = wall thickness ρo = minimum bending radius and εo = minimum bending strain.
where: K
= 1 for minimum performance properties
= 1.5 for average bending resistance with high strain hardening. The first criterion is normally used and implies: K
and the second:
Ovality will be affected by bending and by external overpressure (p), such that:
The maximum bending moment just before buckling, M * , is affected by tensile (or compressive) forces in the pipe:
where M is the maximum allowed moment without tension M
To convert the
*
relation into terms of strain (as required for the bending + buckling
M
criterion) it is necessary to use moment-strain curves (see Figures 1.5-2 and 3) and to observe that ε o now effectively has been reduced in accordance with a decrease of:
This combination of critical bending moment and tension may occur on the stinger.
FIGURE 1.5-2 MOMENT VS CURVATURE AS A FUNCTION OF D/t RATIO FOR API 5LX-42 PIPE
FIGURE 1.5-3 MOMENT VS CURVATURE AS A FUNCTION OF D/t RATIO FOR API 5LX-60 PIPE
1.5.2.5 CollapselBuckling by External Pressure, Bending and Tension The criterion to be used is that for collapse/buckling, i.e. a combination of the criteria for collapse and bending/buckling:
Correction for pc and ε o are to be applied for the tension load T. The influence of tension on pc can be ignored (see 1.5.2.3) if:
The influence of T on ε o is calculated via:
The value of the out-of-roundness function g(r, d) can be obtained from Table1.5-2 by interpolation or by calculation via the formula presented in 1.5.2.2.
1.5.2.6 Buckle Propagation Tests have shown that pipe with a collapsed end or otherwise locally severely flattened pipe will collapse progressively along its length if subjected to external pressure beyond a critical value pp, called the propagating pressure. The most simple approach is to use Batelle's formula:
to decide beyond which water depth, corresponding with pp buckle arrestors should be installed around the pipe to avoid collapse propagation following buckling, e.g. whilst laying or as a result of severe damage by anchors.
1.5.3 Pipe Loads in Conventional Laybarge Laying The equations governing the static 2D suspended pipe span situation are indicated in Figure 1.5-4. By suitable elimination these equations can be reduced to:
Even without allowing for wave and current forces (U = 0), the second equation can only be solved by numerical methods and one of the ways to obtain indications of the top and bottom conditions of the span is to use dimensionless curves, e.g. Figure 1.5-5, which allows deduction of mininum sag bend radius (maximum bending strain) depending on water depth and bottom tension T0. Each parameter is made dimensionless through the submerged weight w (N/m) and the characteristic length Lc = EI
1 3
w
in which El signifies the bending
stiffness of the pipe (product of elasticity modulus E and moment of inertia I). The pipe top end is at the inflection point L = Li; slightly below stinger touch-down point L = Li (see Figure 1.5-6). In this approach T0 may be approximated by taking T0 =
wD 2ε *
where ε * is equal to the
maximum allowable strain in sag bend conditions, following from:
This is a conservative approach towards T0 because it ensures that T0 is too high to allow buckling at L = L * As a next step the tension at the top is given by T1 ≈ T0 + w.Y Total sag bend length is approximately equal to:
The pipe top angle θ can be determined from the dimensionless curves in Figure 1.5-7. If more precise methods are required, e.g. because of the presence of considerable current and inertia forces, then special computer programs should be used of which several versions are available.
FIGURE 1.5-4 NOTATIONS FOR ANALYSING A 2-D SUSPENDED PIPE SCAN
FIGURE 1.5-5 SAG-BEND MINIMUM RADIUS VS HEGHT AT THE INFLECTION POINT To IS THE BOTTOM TENSION
FIGURE 1.5-6 BENDING STRAIN VS DEVELOPED LENGTH OF PIPE SPAN
Cri
FIGURE 1.5-7 ANGLE OF PIPE AXIS VS HEIGHT AT THE INFLECTION POINT. To IS THE BOTTOM TENSION
1.5.4 Suspended Spans of Pipe Laying on Bottom Suspended spans are subject to; - lift and drag forces by steady current - lift, drag and mass forces by wave induced velocities and accelerations - submerged weight forces of filled and empty pipe - vortex induced vibrations. The first two types of forces are usually calculated for extreme conditions, e.g. the 50 or 100 year storm, using data on drag, lift and mass coefficients with the additional conditions that; - steady current velocity is now equal to the undisturbed value at 1.5 m above bottom - wave induced velocity and acceleration must be based on maximum wave height rather than on significant wave height. Bending moments caused by lift, drag and mass forces are occasional loads and maximum stress conditions which include these forces may be judged using the criterion; Seq < Sy (equivalent stress < specified minimum yield stress, provided that all loads, which may occur at the same time, are included, e.g. for gas lines allow for liquid fill). The quantity W, signifying the total distributed load will then not only represent submerged weight but also the components of lift and drag/mass force and the direction of Win the plane perpendicular to the pipe axis will not generally be vertical - as in the examples which follow-but will depend on the size of these forces and on the weight. Suspended spans are pipe runs over bottom irregularities and are generally of two basic types; crossings of the depressions, and crossings of elevated points. The actual configuration of the crossing will be affected by the bottom tension introduced in the pipe during installation; the residual lay tension will tend to minimise bending stresses. For (short) pipe spans for which residual tension may be neglected, beam theory can be used to give approximate formulae for maximum loads. In the following Tables 1.5-3 to 6 basic load cases are given. Note that the support conditions at the ends will only be satisfied to a certain extent for a pipe span problem, and therefore the results are only indicative.
Table 1.5-3a) Basic load conditions for single spans
Table 1.5-3b) Combined load conditions for single span (continued next page)
Single pipe supports may deflect relatively to the others or an additional load may be applied to a pipe end. Table 1.5-4 is intended to indicate superimposable base cases of loads resulting from given deformation. Table 1.5-4 One end deflect, on of a single span
A pipeline may try to expand in longitudinal direction due to temperature or pressure effects. If such expansion is constrained, buckling of free spans can take place. A particular situation may be approximately analysed with the use of Euler's formula. Given the expansion forces PB, the buckle length LB can be estimated from Table 1.5-5 and appropriate support measures taken. Table 1.5-5 Global buckle length of single spans
Symbols: E = Young's modulus, Pa 4 I = Moment of inertia, m L = Buckle span length, m P = Global buckle load, N
A pipeline resting on the bottom may under some circumstances be comparable to a situation where it rests on equally spaced supports. In that case stresses may be checked by using the formulae for uniformly loaded beams over equal spans; see Table 1.5-6 (note that tension is not included in the Table).
Table 1.5-6 Uniformly loaded pipe resting on more than one support (Uniform load per unit length = w; length of each span =1)
The numerical values given are coefficients of the expressions at the foot of each column. Reproduced by permission, from Marks. Standard Handbook for Mechanical Engineers, Eighth Edition, p.5-36, Fig. 46; p.5-37, Table B. McGraw-Hill Book Company The associated diagram shows the values of the functions for a uniformly loaded continuous beam resting on three equal spans with four supports. Continuous beams are stronger and much stiffer than simple beams. However, a small, unequal subsidence of piers will cause serious changes in sign and magnitude of the bending stresses, reactions, and shears.
Table 1.5-6 (continued)
For depression spans, two distinct regions may be defined; (a) the pipespan in the depression given by L (max. bending stress in middle of span), and (b) the pipe span outside the depression given by 1 on either side of depression (max. bending stress at point with max. curvature). (See Figure 1.5-8.) The graphs associated with this Figure allow both maximum stresses, the deflection and the induced span length to be determined. As can be seen from the curves both the bending moment and the deflection will decrease with increased tension. In the dimensionless curves of Figures 1.5-8 and 9 the following parameters are used:
where: El = w = D = T =
2
bending stiffness of pipe, N.m pipe weight per unit length, N/m outside diameter of steel pipe, m tension in pipe, N
Calculated: Characteristic length
Characteristic stress
Dimensionless tension
Taken from curves in Figure 1.5-8:
Maximum bending stresses caused by elevated obstructions are virtually unaffected by variation in pipe tension (symmetrical case with flat horizontal sea bed at either side is assumed). The pipe span length on each side will be affected by the tension. Figure 1.5-9 enables span length and maximum stress to be determined if other influences such as pipe penetration into the sea bed may be ignored. Example: Outside diameter of pipe Wall thickness Uniformly distributed pipe weight w Considered pipe tension T Elevated obstruction Calculated: Characteristic length
Characteristic stress
Dimensionless elevation
406 mm 19.05 mm 511 N/m 290 kN 3.1 m
(16 in.) (0.75 in.) (35 Ibs/ft) (65 kips) (10 ft)
FIGURE 1.5-8 DIMENSIONLESS CURVES FOR DEPRESSION SPANS
Taken from curves in Figure 1.5-9:
FIGURE 1.5-9 DIMENSIONLESS CURVES FOR ELEVATION SPANS
Vortex-induced oscillations occur basically within two adjacent flow regions. The first instability region is accompanied by symmetrical vortex shedding (as if the flow started impulsively from rest at each cycle) and the second by alternate vortex shedding. The parameter Vr, called reduced velocity is generally used to determine the velocity ranges where these instabilities may occur. Vr is defined as:
where: V = flow velocity fn = natural frequency of the pipe span and D = outer pipe diameter As a conservative approach Vr can be taken as 1.0 (occurrence of the first instability region) and safe span length frequencies for single span beams without any pretension or concentrated loads:
(where the most likely value for α = 22.4). As before, the equations are indicative only because boundary conditions for actual pipeline situations are usually not identical with those assumed in Table 1.5-7. Table 1.5-7 Natural frequencies single spans
Symbols: E = Young's modulus, Pa 4 I = Moment of inertia, m L = Length of span, m m = Mass per unit length, kg/m fn = Natural frequency, rad/sec
1.5.5 Buried Lines
Symbols; T1 = installation temperature T2 = max. or mm. operating temperature 0 -4 -1 α = thermal expansion coefficient (steel up to 100 C: 0.115 x 10 K ) ν = Poisson's ratio = 0.3 (steel) E = Young's modulus ∆ = pipe movement t = wall thickness La = pipeline anchor length f = friction force per unit length λ = decay length for exponential distribution of pipeline temperature Rm = mean pipe radius Sh = hoop stress Sl = longitudinal stress Sy = yield stress Other symbols as in Table 1.5.1
1.5.5.1
Limitation:
Fully Restrained Parts
1.5.5.2
Anchor Force
Assume result equivalent to fully restrained line:
1.5.5.3
Moving Portions (Partly Restrained)
The length over which movements occur (La) can be estimated as follows:
The element exp. (-La /λ) represents the temperature decay over the anchor length. Assuming uniform temperature in the pipe, the element exp. (-La /λ) can be given a value equal to unity. Pipe Movement
Note: if an end restraint force, such as caused by a riser or an expansion loop, is present then the previous two equations must be modified to account for this effect.
1.5.5.4 Lateral and Longitudinal Movement (This page to be read together with the next page.)
1.5.5.5
Upheaval Buckling
When a pipeline is subjected to an axial load, the pipe will tend to move in the vertical plane or along the trench side slope when the pipe is not covered. This phenomenon is called upheaval buckling (offshore) or overbend instability (onshore). The pipeline response might then be unacceptable in terms of vertical displacements (the pipe protruding through the cover or moving out of the trench), excessive yielding of the pipe material, or both. Upheaval buckling is hence a failure mode that has to be taken into account for the design of trenched and buried pipelines operating at elevated temperatures. A simplified calculation method is detailed below. For advanced calculation refer to guideline EP-90-2539. The additional symbols used are: C = soil cover shear strength Do = pipe outside diameter over coatings f = uplift coefficient H = soil cover from top of pipe to surface min = the smaller of the two values Wins = installation submerged weight Wsub = operating submerged weight γ = soil submerged weight ∆f = foundation imperfection height
[kpa] [m] [m] [kN/m] [kN/m] [kN/m3] [m]
The axial compressive driving force is:
The uplift resistance in cohesionless soil or rock fragments is:
The uplift coefficient f should be taken as 0.5 for dense sand or rock cover and as 0.1 for loose sand. The uplift resistance in cohesive soil is:
The required downward force is given by:
The foundation profile imperfection height ∆f is a measure of the roughness of the seabed. The recommended value for design purposes is 0.3 [m]. To prevent upheaval buckling the uplift resistance Weft should exceed the required downward force Wreq.
1.5.5.6 Weight Load on Buried Pipe
Stress Caused by external load from above = Bending stress at point A. For assumed reasonably well compacted backfill this stress is
L = wheel load, N w = pipe load, N/m D = outside pipe diameter, m t = pipe wall thickness, m E = Young's modulus, Pa p = Internal pressure, Pa Cd = load coeff. (see Table 1.5-9) BD = width of trench at pipe top, m H = depth of pipe top, m Kb and Kz are coefficients defined by trench type (see Table 1.5-8) If = impact factor (see Table 1.5-8) -3 γs = soil weight N.m Table 1.5-8 Values for Kb, Kz and If
Table 1.5-9 CD values for pipe in trenches as function of H/BD
1.5.6 Risers Riser design must take account of variations in temperature, internal pressure and external environmental loads anticipated throughout the lifetime of the system. Installation loads may also vary considerably with the installation method adopted (see 2.2.2.3). An example riser model is shown in Figure1.5-10. Inspection/maintenance requirements (see 3.4) and potential hazards and risks (see 1.7.3) must also be considered. A typical riser calculation sequence is as follows: 1. Establish temperature profile along the riser and the adjacent pipe section (see 1.1.4). 2. Estimate maximum pipeline expansion/contraction due to pressure and temperature changes which will occur at the interconnection between the riser and the pipeline (see 1.5.5). 3. Calculate riser stresses due to: (i) Operating condition: includes imposed pipe-end displacements combined with extreme values of functional and environmental loads (ii) Hydrostatic testing condition: includes pipe-end displacement, functional loads and environmental loads generated by a one-year return storm (iii) Installation condition: anticipated installation loads. 4. Apply criteria dictated by applicable codes (see 1.5.1). It stresses are too high, modify design by including an offset or alternatively an expansion loop in the pipeline adjacent to the riser. Then, repeat above analysis from activity 2. 5. Check riser clamp distances to be within allowable riser spans with regard to vortexshedding induced vibrations (see 1.4.1 and 1.4.3.2). 6. Identify stress sensitivities with respect to uncertain design parameters. In particular it is important to check stress sensitivity due to deviations in assumed: (i) Temperature ranges (ii) Burial/scouring of pipe sections next to the riser (iii) Installation imposed stresses. A riser is normally anchored close to the topside facilities to minimise expansion forces imposed on deck piping.
FIGURE 1.5-10 EXAMPLE RISER MODEL
1.6
Design Requirements for Internal Inspection Tools
It is recommended that scraper traps (see 2.5) and pipelines are designed such that they can accommodate an internal inspection tool (see Figure1.6-1). Note: See Table 1.6-1 for approximate lengths of A and B for different diameters.
FIGURE 1.6-1 SCRAPER TRAP LENGTH CONSIDERATION WHEN USING INTERNAL INSPECTION TOOLS
The approximate maximum length of tool and corresponding trap length are shown in Table 1.6-1. The minimum acceptable ratio bend radius/pipe diameter (and minimum straight length between bends) depends on pipe diameter and wall thickness, and is typically 5 or 8. The exact limit may vary for different inspection tools, so it is recommended to first consult potential survey companies. Large variations in pipe internal diameter (d) should be avoided as this may cause problems (see also 3.4.3 on pipeline inspection tools).
Table 1.6-1 Pig trap lengths for internal inspection tools
2
CONSTRUCTION
2.1
Landline Construction
2.1.1 Codes and Permits The regulations most generally applied for the construction of pipelines are the ANSI codes B31.4 and B31.8. These both refer to API 1104 for specific welding requirements. Another well known code is BS 8010 which refers to BS 4515 for welding aspects. In many countries there are specific national requirements which may be stand-alone documents or additional requirements to other codes such as B31 .4. There is also likely to be a range of local requirements covering land purchase, rights of way, easements, conservation, etc.
2.1.2 Surveys, Landline Construction There are two general categories of pipeline survey; land and marine. This section outlines the procedures used for land surveys (see 2.2 for marine surveys). Other types of terrain can be covered by a combination of these two types with the occasional addition of a particular, specialised technique. A preliminary desk top study is carried out to study possible routes (scale 1:1000). A route for a pipeline is then chosen on the map such that it is the shortest possible distance between the two endpoints, whilst at the same time permitting economic design and construction. A detailed site survey is then carried out where the route is fixed on the ground surface relative to known benchmarks or fixed points (if existing). A report is made of topographical features along the route (hills, deltas, rivers, canyons) together with obstacles in the immediate vicinity of the route (houses, roads, cables, economic crops, land owners and other pipelines). For a buried pipeline, a geotechnical survey is often made which yields information such as the subsurface geological conditions likely to exist along the pipeline route. A topographical survey is always necessary to obtain construction permits, operating licences, and easements, as well as data for the design of the pipeline.
2.1.2.1
Land Survey Specifications for Pipelines
An aerial survey is to be used to establish the pipeline route which is then marked on the aerial photographs and a large scale map, preferably at a scale of 1:50 000.
The route is then staked out, if possible with firmly fixed markers, so that each marker is visible from adjacent markers. In desert country the markers should be placed at least every 500 metres. Distances along the pipeline route (chainages) are measured for all markers, obstacles and topographic features to an accuracy of 1:20 000. Horizontal angles or bearings and distances, which are relative to the local co-ordinate grid system, should be measured with instruments permitting a final accuracy of 1:20 000. Elevations of every variation in the terrain are measured to a well defined datum. The accuracy of the levelling traverse should be better then 2L cm, where L is the distance between the end points of the traverse or loop in km. A traverse is surveyed along pillars or markers every 5 discriptions of these survey survey report together with elevation datum.
the pipeline route and marked by firmly fixed permanent survey km within 500 metres of the pipeline route. Proper station points and their reference markers should be included in the the parameters of the local co-ordinate grid system and the
The survey report should also contain photographs or sketches of obstacles and features within 100 metres of the pipeline route, a longitudinal profile (in general at a scale of 1:10 000 to 1:2500 horizontal and 1:1000 vertical), and a planimetric stripmap of the pipeline route showing features, elevations, per-manent survey markers and eventual boundaries with their appropriate landowners. The stripmap should show the local co-ordinate grid system and grid projection information.
2.1.2.2
Geotechnical Survey
A geotechnical survey starts with a desk study by a geologist, which is then confirmed by correlation with observed surface features. Pits or boreholes are then made to the pipeline burial depth at 1 km intervals, and referenced to the route survey. The results are then graded according to ease of trench excavation, e.g. standard backhoe, D-9 tractor ripper (up to two passes), and rock blasting. In some locations a ripper survey can be carried out instead of a borehole survey, as can certain seismic or ultrasonic techniques which give information on the near-surface geology.
2.1.2.3
As-Built Surveys
An as-built survey is made of the pipeline after construction and is reported on a planimetric strip map of the pipe route. Typically this has a horizontal scale of 1:2500, and a vertical scale of 1:1000 and gives details of features, pipe, cable and road crossings on a map with the local co-ordinate grid system, as well as pipeline burial depth, ground-level, chainages, bends and cathodic protection points.
2.1.3 Construction General 2.1.3.1
Inspection Requirements (including Pearson Survey)
Pipeline construction operations tend to be spread over considerable distances and to involve extended working hours. It is essential to provide adequate and sustained inspection of all activities with particular emphasis on welding, coating, lowering-in, backfill and testing. All inspectors should have a good knowledge and previous experience of the activities they are to inspect. Inspectors employed for the critical positions of senior pipeline inspector, all welding /NDT inspectors and coating inspector(s) should be thoroughly assessed including, where appropriate, a personal interview. They should be in possession of valid qualifications such as the British Gas Corporation's ERS approval or equivalent. Reference should also be made to Central Offices who maintain records of suitable qualified inspectors and can assist where required in screening inspectors. Prior to the start of construction, an Inspector's Manual should be prepared and issued to all inspectors, clearly defining the responsibilities, work and reporting requirements of the inspection team. It should also include the technical specification and any guideline notes that may be useful for inspecting the work as executed by the contractor. It is emphasised that the quality and consequently the lifetime of a finished pipeline depends largely on the quality of inspection. Pearson Survey: This is a method of detecting holes (holidays) in a pipeline coating after the pipeline has been buried, by locating points on the ground above a pipeline, where a sensing signal is picked up by emission from a break in the coating. There are various techniques for ensuring accuracy of the readings and it is advisable to employ reliable apparatus in the hands of experienced operators. A number of specialist CP and Inspection contractors offer this service which is a useful method of monitoring the condition of the pipe coating after backfill and during operation.
2.1.3.2
ROW/Working Strip
Prior to starting construction the pipeline, the owner will need to obtain a permanent easement and a temporary working strip which should be of sufficient width to provide for economic construction. The required width will depend on the type of terrain and the pipe diameter. Where the possibility exists of a second pipeline being installed at some future date, it is recommended that additional easement is negotiated at the same time as for the original easement. The limits of the working strip should be clearly marked and if applicable temporary fencing with access gates must be erected. Before work starts a pre-entry record should be made of any existing special features so that they may be adequately reinstated after construction is completed.
2.1.3.3
Clearing/Grading
Where applicable, top soil should be removed and stored separately prior to grading/trenching. The width and depth of top soil stripping, if any, will be governed by local circumstances. Clearing should include the removal of all obstacles to construction works such as trees, brush, crops, boulders, fences, etc. Subsurface obstacles such as tree stumps, roots, etc. in proximity to the pipeline should also removed. The working strip should be graded/levelled as required to permit transit and operation of construction vehicles and equipment and to permit placement of the pipeline at the desired elevation (see Figure 2.1-1).
2.1.3.4
Trenching
Pipelines will normally be laid to ground contour with a specified minimum cover. Trench dimensions vary with pipe size, nature of the terrain, applicable regulations and other factors. However the ditch should be wide enough to permit:
FIGURE 2.1-1 TYPICAL EXCAVATION AND BACKFILL OPERATIONS
(a) The pipeline to be lowered without damaging the coating (b) The backfill to settle around the lower part of the pipe (c) The removal of slings without damage to the coating (d) The pipe to fit the ditch without the use of external force. For typical trench dimensions see Figure 2.1-2.
FIGURE 2.1-2 TYPICAL TRENCH DIMENSIONS
The method of excavation will depend on the type of terrain. In areas of rock where blasting is required it is imperative to follow the strict regulations covering the use of explosives that are applicable in most locations. Blasting also needs to be restricted near to buildings and/or other pipelines and, where required, fly rock mats must be used to prevent damage to adjacent property. If necessary ground vibration levels should be monitored to ensure they are within acceptable limits. Excavation in the immediate vicinity of existing pipelines/cables and other underground obstacles should be by hand to avoid damage. It is normal for new pipelines to cross under existing pipelines/cables and at such locations the trench depth should allow for a minimum clearance of 300 mm, between the new pipeline and the existing facility. (For special requirements at road/rail and water crossings, etc. see 2.1.4.)
The bottom of the trench should be prepared to permit even bedding of the pipeline and should be free from all objects or materials that might cause damage to or deteroriation of the coating. For typical trench configurations see Figure 2.1-3. FIGURE 2.1-3 TRENCH CONFIGURATIONS
2.1.3.5
Material Handling/Transport/Slinging
During all material handling, transporting and slinging operations, care must be taken to avoid damage to the line pipe and coating. Pipes shall be lifted carried and placed in position. Lifting operations should be carried out using wide slings (mm. width = pipe dia.) made from non-abrasive material or special lifting hooks designed to fit pipe curvature and protect bevelled ends. When storing or transporting pipe, special attention should be paid to weight distribution to prevent flattening of the pipe and/or coating damage (pipe supplier's recommendations on maximum stacking height should be followed). Where ground conditions could lead to damage to pipe/coating, pipes should be placed on suitable packing to avoid contact with the ground surface. During transportation pipes should be loaded and stacked in such a manner that flexing and movement of the pipe is avoided; wide non-metallic slings shall be used to secure the pipe (refer also to API RP 5L1 and RP 5L5). Pipes should be strung so as to cause minimum interference with the land crossed. Where the possibility of blasting exists, trenching shall be carried out ahead of stringing to prevent damage to pipe caused by blasting.
2.1.3.6
Bending/Tie-In
Bending All field bends (cold bends) should comply with the minimum requirements of the ANSI B31.4/B31.8 Codes and should generally conform to Figure 2.1-4.
Tie-ins To prevent joints being left under stress, tie-ins should be properly aligned without the use of external force. When tying-in long lengths of exposed pipe due consideration must be made for temperature effects. All tie-in welds should be subject to 100% NDT.
FIGURE 2.1-4 FIELD BEND
2.1.3.7
We/ding/NDT (see 2.3)
2.1.3.8
Field Joint Coating/Coating Inspection
The uncoated external portion of the pipeline joint should be protected to a standard equivalent to and compatible with the line pipe coating. For details of the various types of field joint coatings and their suitability see 1.3.4.
Immediately prior to lowering-in, the whole of the pipeline coating should be carefully examined by means of a holiday detector, the setting of which should be suitable for the thickness and nature of the coating material. All defects located should be clearly marked and repaired before the pipe is lowered.
2.1.3.9
Lowering-In
Before lowering-in is commenced particular attention should be paid to the suitability of the trench to allow the pipeline to be lowered without damage to the coating and to give an even support to the pipeline. Where excavated material is unsuitable, e.g. in rock areas, the trench bottom shall be padded with sand or similar material to support the pipe at least 150 mm off the high points of the bottom prior to lowering in. Wide non-abrasive belts or rubber tyred roller cradles should be used and throughout the lifting and lowering operation care should be taken to: avoid damage to the protective coating and overstressing the pipe. The pipe shall fit the trench without the use of external force to hold it in place until backfill is completed.
2.1.3.10 Backfill/Clean- Up/Reinstatement Backfill should follow closely on the lowering of the pipe so that the pipe coating is exposed to accidental damage for a minimum period. Fine grade material free from sharp edged stones should be used and carefully compacted all around the pipe to a minimum consolidated height of 150 mm above the pipe. Where excavated material is unsuitable, e.g. in rock areas, sand or equivalent material must be imported. (See Figures 2.1-1 and 2.1.-3.) On sloping ground care shall be taken to prevent the backfilled trench forming a natural drainage channel.
In remote areas, e.g. deserts consideration should be given to forming a windrow/bund over the pipeline to prevent vehicles, etc. crossing the pipeline at points other than planned crossing points. However adequate breaks in the windrow should be provided to prevent excessive water build-up during rain storms. As soon as possible after backfilling, the site should be cleared and all surplus materials removed. Rock excavated from the trench can be a major clean-up problem especially where land is cultivated. The working strip should then be reinstated as nearly as possible to its original condition.
2.1.4 Special Construction Some aspects of construction require the use of specialised equipment and procedures, and in some cases specialist organisations/contractors in order to perform it. These specialists often work as sub-contractors but where the work can be considered as a major project in itself, e.g. large river crossings, such projects may be contracted for separately for economic and/or time constraint considerations.
2.1.4.1
Water Crossings
In general, pipeline crossings of major rivers, canals or other bodies of water are more expensive on a cost per unit length basis than nearly any other type of pipeline construction. Preparation of the ditch across many water courses is itself a major cost item and as a consequence, in exceptional cases, additional pipelines have been installed as spares for future use. The pipeline must be buried in the stream bed well below the future scour level and factors such as plans for future widening, deepening for navigation purposes, or flood control schemes must be taken into account during both design and construction. In some cases installation of the crossing is only permitted within certain periods to avoid interference with navigation, seasonal fishing or other considerations. Construction procedures vary widely because of the unique features of each crossing but it is quite common that the pipeline string/strings are made up on land prior to pulling into place. The pulling into place is made easier in some cases by the installation of temporary floats attached to the pipeline to reduce the submerged weight and hence the pulling force required. Hydrostatic testing of the pipeline string/strings is performed prior to installation because of the difficulty and high cost of finding and repairing leaks after the pipe is in place.
Further hydrostatic testing is performed after installation and again after backfilling unless natural backfill mg is allowed to occur. Depending on pipeline diameter, it contents, soil conditions, current velocities etc., it is often required that the pipeline be provided with a concrete weight coating to provide adequate stability. Extra wall thicknesses may be required to overcome additional stresses in the pipe due to the necessity for it to conform to natural flexing in the installed position. Extra wall thickness may also be used to increase the design safety factor of the crossing. It is usual to install isolation valves on both sides of major water crossings. For a typical sketch of a minor stream crossing see Figure 2.1-5.
FIGURE 2.1-5 TYPICAL DITCH AND MINOR STREAM CROSSING
2.1.4.2
Road/Rail Crossings
Wherever possible, installation of road crossings should be carried out by the uncased method. On minor roads this can be achieved by open-cutting the road but on major trunk roads or other heavily utilised roads the thrust bore technique is used. Normally the local legislative authority will dictate which roads can be open-cut and which are to be thrust bored. Extra wall thickness may be required in some cases to overcome additional external loading problems and this should be identified at the design stage. Alternatively local legislative authorities may stipulate the use of extra wall thickness pipe at certain road crossings. Rail crossings generally have to be constructed by the bored technique and again the uncased crossing method is preferred, however, it is very common for railway companies to insist on the installation of cased crossings. Where such crossings are to be used, it is essential to ensure that the pipeline is adequately supported on either side of the crossing such that settlement of the carrier pipe and hence direct contact with the casing pipe is avoided. An additional problem associated with cased crossings is the ineffectiveness of the cathodic protection system to protect the carrier pipe inside the casing. Recommendations on pipeline crossings of roads and railways are contained in API RP 1102. For typical sketches of both cased and uncased crossings see Figures 2.1-6 to 9. FIGURE 2.1-6 TYPICAL CASED RAILWAY CROSSING
FIGURE 2.1-7 TYPICAL UNCASED ROAD/RAIL CROSSING
FIGURE 2.1-8 TYPICAL CASING INSTALLATION DETAILS
FIGURE 2.1-9 TYPICAL CATHODIC PROTECTION AND TEST CABLE CONNECTION
2.1.4.3
Unstable Soil Conditions
Soils with low load-bearing capacity may exist for considerable distances along a pipeline route. To be able to install the pipeline, special provisions may be necessary to support construction equipment and to maintain the ditch open for sufficient time to install the pipeline. Such measures may include construction of log 'rip-rap' access roads and well pointing or ground dewatering. Alternatively the construction of channels for floating the pipeline into position or even canals for the use of floating equipment may be necessary particularly in swamp areas. A further problem with this type of soil, particularly if it is saturated with water, is the buoyancy of the installed pipeline which can cause the pipe to float to the surface after installation. This is particularly relevant for larger diameter and/or gas pipelines. Weighting or anchoring of the pipe may be necessary in order to maintain the pipeline at the buried depth although in some cases backfilling with specially imported material can be carried out. Weighting of pipelines can be achieved either by a continuous concrete weight coating or by bolt-on or set-on gravity weights. Set-on gravity weights of concrete are the most economical of the gravity anchors, however, great care is necessary in both their design and installation to protect the pipeline against possible damage. Mechanical anchoring, using the steel auger type of anchor, is probably the most economic method of anchoring pipelines over extended lengths. The steel anchors are driven into the ground alongside the pipeline and attached to the pipe with some sort of strap. Mechanical anchors achieve their holding power from the shear strength of the soil. Where used it is necessary to test their hold-down capacity after installation to determine their adequacy. If necessary anchors must be driven to a greater depth or alternatively additional anchors installed to achieve the overall hold-down capacity required. A disadvantage of mechanical anchors is that different soil types may require differently designed anchors and installation in areas containing rock or boulders is difficult. Of the methods available for weighting or anchoring pipe to maintain the required depth, the continuous concrete weight coat is the most reliable, albeit the most expensive, to install (see also 1.4.1). Before selecting a method for anchoring it is essential to conduct a thorough investigation along the pipeline route of the soil type, strength and any other tests pertinent to anchor design.
2.2
Submarine Line Construction
2.2.1 2.2.1.1
Survey Pipeline Pre-Lay Surveys/Sea-Bottom Survey Procedures
Objectives To identify the most suitable route for a pipeline which may be laid on the seabed or trenched and buried below the seabed. Potential problems which may require identification include: - Seabed topography and bathymetric features which may produce adverse slopes, gradient changes or freespan formation - Wrecks, boulders, coral outcrops or other objects which may damage the pipe during laying, hinder the laybarge, cause excessive abrasion on the pipe or the formation of freespans - Seabed and sub-seabed geology and soils types. Thickness and properties of soils units within 2 to 5 metres of the seabed which may dictate trenching and burial methods, or the most economic way of 'smoothing' the seabed.
Survey Pattern After an initial desk study or a reconnaissance survey line, a corridor must be covered, say 500 metres wide, for optimum route selection. A minimum of three survey lines should be run, centred on the proposed pipe route, employing the simultaneous operation of the selected survey systems. Regular tie lines, perpendicular to the major survey lines should be run to ensure good agreement of data. Additional longitudinal lines and tie lines must be run if further data are required in difficult areas to ensure that sufficient information is available for route planning and pipeline design.
Comments On-board data interpretation by qualified personnel should be undertaken to ensure data obtained are sufficient for the survey objectives. This will also ensure optimum selection of sites for seabed sampling (if required). A pipeline engineer should also be on board to assist in the survey pattern modification if any route deviations are required on the basis of the data obtained. In deep water areas where layback errors to tow fish mounted sensors will become large, a tow fish positioning system such as the Simrad HPR should be employed. Survey line spacing must be selected to provide 100% overlap of data.
2.2.1.2
Pipeline Post-Lay Surveys/Sea-Bottom Survey Procedures
Objectives To inspect a pipeline either laid on or trenched and buried beneath the seabed. There may be several objectives including; - To accurately map the as-laid position of the pipeline - To monitor the depth of burial or condition of pipeline trench where appropriate - To monitor changes in sediment cover with time, especially in areas of mobile seabed sediments, e.g. sand wave areas or sand banks - To ensure no suspensions or freespans have been produced either during the laying or at a later date - To monitor any freespan rectification or other pipeline maintenance - To monitor debris accumulation along the pipeline and to monitor sites of potential or actual damage to the pipeline.
Survey Pattern At least one survey line should be run along each side of the whole length of the pipeline utilising echo sounder and sidescan sonar. When surveying along exposed or trenched pipe, the vessel's track must be controlled from the sonar records. The exact position of the pipe can only be plotted by means of regular pipe crossings, using an echo sounder or, if the pipe is buried, a microprofiler which is either hull mounted, towed on a short cable or monitored with a tow fish positioning system. Trench conditions, exposed pipe conditions or problem areas are best examined by means of a combination of short sonar and profiler lines run in the area of interest.
Comments The sonar will provide an overview of the pipeline condition along its whole length and the pipe crossings will provide more detailed information on the pipe at a number of points along its length. The accuracy of the results will depend not only on the inherent accuracy of the survey systems but also on the way in which they are operated and then interpreted. These 'remote' systems will not consistently detect minor damage or low order pipe suspensions above the seabed. It is therefore essential that a video inspection (usually by ROV) is made of the pipeline after laying and then at any points where problems are identified on subsequent surveys. Since the survey vessel's track must be controlled from the sonar records, the chosen vessel must be manoeuvrable and responsive.
The accuracy of data obtained from the sonar and microprofiler systems depends upon the accuracy of the sensor positioning. If sensors are not hull mounted or towed close to the vessel, a tow fish positioning system such as the Simrad HPR should be employed. All charting and reporting of annual surveys should be in a format to allow easy comparison of data, particularly in problem areas. Small diameter pipes, or pipes in areas of irregular topography or boulder concentrations may require more sophisticated survey techniques. Other survey systems have been developed for remote sensing of pipelines, e.g. sector scan sonar, GVSS (colour processed sonar data), multi-transducer pipe tracking devices. These have been used with limited success but are considered outside the scope of this brief overview.
2.2.1.3
Positioning and Survey Equipment
Positioning equipment for survey and construction vessels A large variety of radiopositioning systems for surface vessels exist, all with their pros and cons. Only a summary can be given here. In all cases the Topographical department should be consulted for further details. The following criteria govern the choice of a survey system: - Distance from shore - Accuracy requirements, both in absolute and in relative sense - Number of craft involved - System's availability, frequency allocation and economics. General statements: (a) The higher the frequency, the shorter the range (b) The higher the frequency, the greater the accuracy (c) There is no system which does not suffer from ambiguities and adverse propagation effects, whether they be skywave or other reflections, land-and seapath anomalies or ambient radio noise (d) All systems need thorough hardware calibration (e) All systems need continuous, real-time quality control by qualified and experienced survey personnel; redundancy of position lines for this purpose and as a safeguard against gross errors is essential. Some of the most common multi-user systems for pipeline operations are shown in Table 2.2-1.
Table 2.2-1 Multi-user positioning systems
The c.w. (continuous wave) systems suffer much more from instability due to moving cranes, etc. and from skywave effects than pulse systems. The accuracy for all systems except Pulse-8 can vary from a few metres under ideal conditions to several tens of metres and worse under adverse conditions. For Pulse-8 the best accuracy achievable is of the order of 25-50 metres.
Survey Equipment Bathymetry Hydrographic echo sounder such as Atlas Deso 10, Deso 20, Simrad EA (or equivalent). Calibration by 'bar-check', and salinity/temperature or velocity meter, pre-, syn- and post-survey. Tidal corrections to LAT should be checked against a tide gauge installed in the area for the duration of the survey.
Sidescan Sonar Dual channel high frequency (100 kHz) system such as EG + G, Klein (or similar) system shall be capable of single channel operations with data display on a recorder with sweep speeds of up to 1/16 second. Tow cables must be carefully monitored to permit accurate layback calculations. System shall be operated at sweeps commensurate with optimum resolution, continuous tracking of pipeline route and 100% data overlap. As a rule of thumb, fish height above seabed should be 10% of range. All sonar data shall be taped.
Sub-Bottom Profiler High resolution, short pulse length source such as EG + G Uniboom. Prior to acceptance of equipment, the boomer signal shall be monitored to ensure a resolute, repeatable, outgoing source signature. Graphic recorders shall be capable of 1/16 second sweep. All data should be taped to permit replay at expanded scale. Control of data is essential to ensure data will meet survey objective. Note: In very soft seabed conditions a 'pinger' source may be suitable but such a system is not generally recommended.
Seabed Sampling Either a gravity corer or a vibrocorer depending on expected seabed conditions and depth of interest below seabed. Careful logging of samples and storage is essential. Laboratory testing of samples is required.
Debris/Obstruction Detection Sidescan sonar will be adequate for most projects. If buried cables are expected, a magnetometer may be required. On infield routes, close to existing facilities, a visual inspection of problem areas is recommended utilising either diver or ROV video systems.
2.2.2 Construction 2.2.2.1
Pipeline Installation Methods
Laybarge This is the most common method for submarine pipeline installation. The production line of a laybarge is usually limited to installing a single line at a time. Pipeline bundles can be laid using a laybarge, but the line-up problems involved and the low laying speed make it in general unattractive both technically and economically. A pipeline is normally initiated by positioning a 'dead man' anchor on the seafloor attached to the first pipe joint via a cable. During laying a pipeline the barge moves on its anchors. These anchors and anchor cables used for moving and holding the barge in position can damage existing pipelines and structures in the vicinity of the laybarge. To minimise the risk of damage to other facilities detailed anchoring plans should be prepared beforehand by the lay contractor. During laying the contractor should continuously record the applied tension to the pipe to ensure that the approved laying procedures are being followed. The required tension should be determined such that the pipeline departs the stinger some distance up from the last roller.
Load cells in the roller cradles together with a TV camera permit the monitoring of the pipe behaviour. In adverse weather conditions the pipe should be abandoned by lowering to the seabed via a cable, before impact against the stinger rollers results in excessive damage to the pipe coating.
During laying of the pipeline a buckle detector should be pulled through the pipeline at the touch-down point of the pipe on the seabed to confirm that the pipeline has been laid buckle-free. The buckle detector is a simple steel frame equipped with rollers and a steel plate with a diameter slightly smaller than the pipe internal diameter. It is connected to the barge via a cable which should be fitted with a weak link arrangement, a tension meter and an alarm.
Reel-Barge The reel-barge installation method permits the installation of pipeline up to Dn 400 (16 in.) in diameter. Tests should be carried out to check the corrosion coating behaviour during reeling/unreeling. The maximum length that can be installed in one continuous section depends on pipe diameter, reel capacity, and barge capabilities but up to 22 km of Dn 250 (10 in.), or 9 km of Dn 400 (16 in.) pipeline is possible (Apache reelbarge). Pipeline bundles can be installed by means of the reel-barge technique; individual pipes are unreeled from separate reels and bundled together at the stern of the barge. Portable reels in conjunction with locally available equipment can be used to lay flexible lines. When the use of flexible flowlines is considered it is recommended that advice is obtained from SIPM.
Vertical or J-Lay Method This method is primarily of interest for installation of pipeline in very deep water. To date its application has been mainly restricted to tests and it requires the use of a single station welding technique, e.g. friction welding, flash butt welding, electron beam welding, and others which are not as yet fully proven or developed.
Tow Methods Table 2.2-2 outlines the alternative tow methods that are available. Installation by a tow method may be particularly attractive for shore approaches, shallow water areas, short lengths of pipeline or for complex bundles.
Table 2.2-2 Tow methods for laying offshore pipelines (continued next page)
2.2.2.2
Offshore Tie-Ins
Underwater tie-ins between pipeline sections and pipeline to riser connections utilise similar techniques and can be divided into three categories. - Welding - Flanges - Mechanical connectors. Welding In general welding is the preferred method for permanent tie-ins wherever practicable. The welding can either be performed at the surface or subsurface. At the Surface The pipeline is lifted to the surface using davits. Where the length of the pipe required to be supported exceeds the length possible from the barge, usually occurring in deeper water, additional supports can be provided by the fixing of buoyancy floats to the pipeline. The welding is carried out with conventional welding procedures. The method is fast but, generally, is limited to shallower waters and to the smaller pipe diameters. Sub-Surface Sub-surface or hyperbaric welding is performed with the pipeline on the seabed. Special frames are required to align the pipeline and the welding itself is performed in a special habitat. The systems presently available are operated from a barge or a diving support vessel. The method requires extensive diving capability and special welding procedures. As an alternative to hyperbaric welding, the weld can be performed inside an atmospheric chamber into which the pipeline is pulled. However, this method requires further development to be fully operational and is not presently recommended. Flanges Flanged tie-ins performed by divers on the seabed are effected by installing a flanged make-up spool between the flanged ends of the lines to be connected The spool is fabricated at the surface to the exact dimensions required, using a template which has been made up on the bottom and retrieved at the surface. Ring-joint flanges are used for sub-sea installation and to assist in making up each pair of flanges, one of the flanges is normally of the swivel ring type. Uniform tightening of the flange stud bolts can be achieved by hydraulic bolt tensioners. This bolt tensioning method should be used wherever possible.
Flexible spools, such as made by Coflexip (small diameters only), can be installed directly without the necessity of preparing a template, and can considerably speed up the tie-in work. Flexible spools also have the ability to accommodate thermal expansion/contraction. Mechanical Connectors Mechanical connectors are alternatives or supplements to flanges and can offer certain advantages depending on their design, e.g.: - some are easier to install (boltless flanges) - some can accommodate a degree of misalignment (ball joints) - some can be installed directly onto the bare pipe end. A variety of mechanical connectors are available and they generally consist of two components: - A gripping system to anchor the connector onto the pipe - A sealing system using either metallic or elastomeric seals. The reliability of mechanical connector systems cannot as yet fully compete with the quality of a welded or flanged connection, and hence these connector systems are mainly used for emergency repairs to pipelines where time is essential and the equipment for other repair methods is not available. A development of the mechanical connector is the type that can be activated from the surface by hydraulics and without direct diver intervention. To achieve this type of connection, accurate positioning of the end of the pipeline is essential. Once positioned, the pipeline is pulled into the connector which is activated and clamps around a special hub fitted to the end of the pipeline. 2.2.2.3
Riser Installation Methods
Pipeline risers can be installed: - either as a specific pipe section which is tied to the pipeline at the bottom of the platform (see 2.2.2.2), or - as an integral part of the pipeline itself, which is pulled up to the platform deck. Three basic types of riser installation fall into this second category: Pull Tube (see Figure 2.2-1) The pull tube method utilises a curved conduit having an inside diameter several inches larger than the pipeline outside diameter. The conduit is constructed as an integral part of the platform during onshore fabrication.
A cable is passed from the deck of the platform through the conduit to a special pulling head welded to the end of the pipeline. The end of the pipeline is positioned on the bottom in alignment with the mouth of the pull tube. The pipeline riser is then pulled through the conduit to the surface using a winch located on the platform deck. Installation of the riser by this method can be done without divers (for example the 12" Cognac pipeline, Shell Oil - 300 m water depth).
Bending Shoe (see Figure 2.2-2) This method consists of installing a curvature limiting shoe on the platform during the onshore fabrication. The pipeline is laid along the platform and positioned under the bending shoe. It is then bent around the shoe under tension and secured in specially designed clamps. This method can also be used for concrete coated pipelines. Barefoot Riser (see Figure 2.2-3) This method consists of approaching the platform with the pipe suspended vertically at the water surface. The pipe is then positioned tangent to and in contact with the upper end of a series of pipeline clamps on the platform. The lifting load is decreased according to a prescribed schedule which forces the riser pipe into each successive clamp and puts the bottom span into compression. The riser is then secured into the clamps once the desired curvature in the sag-bend is achieved.
FIGURE 2.2-1 PULL TUBE METHOD
FIGURE 2.2-2 BENDING SHOE METHOD
FIGURE 2.2-3 BAREFOOT RISER METHOD
2.2.2.4
Riser Clamps
Depending on the type of riser installation to be employed (see 2.2.2.3) clamps may be required on the jacket to support the riser. In some instances it may be possible to pre-install the clamps on the jacket prior to installation of the structure offshore but often the clamps are installed on the jacket after the jacket itself has been installed offshore. Selection of riser and jacket clamps should be such that the difficulties of installation offshore of both the clamps and the riser are minimised. Practical installation aspects such as: - alignment between top and lower clamps - proper marking of clamps and positions on jacket - handling of clamps subsea by divers - positioning of clamps by means of locating rings - opening and closing of clamps for riser setting and removal (hinges recommended) - adjustability of clamps to accommodate installation tolerances - access to and clearance around bolts for tightening. should be considered. In general the top clamp on a riser is the clamp which supports the weight of the riser. Lower clamps locate and restrain the riser in the horizontal plane but may permit axial movement of the riser. Generally clamps which are clamped around the riser pipe are provided with a neoprene type lining. Depending on specific requirements different types of clamps can be utilised to fulfil the different functions required. Some examples of clamps with different degrees of adjustability and riser constraints are shown in Figures 2.2-4 to 2.2-6. For the structural design of clamps the API RP 2A (Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms) and AISC (Specification for the Design, Fabrication and Execution of Structural Steel for Buildings) are generally used.
FIGURE 2.2-4 TYPICAL CLAMP FOR ANCHORING RISER AT TOP OF JACKET
FIGURE 2.2-5 TYPICAL CLAMP WITH LIMITED DEGRESS OF FREEDOM FOR ADJUSTMENTS
FIGURE 2.2-6 TYPICAL CLAMP WITH COMPLETE FREEDOM FOR ADJUSTMENTS
2.2.3 2.2.3.1
Submarine Protection Trenching
Trenches can be made by dredgers for river crossings and shore approaches. Backfill is in general required in these areas in order to protect the lines against scour and breaking wave impact. The possibility of soil liquefaction during backfilling operations should be evaluated. A high pipe weight is in general required to combat float-up through soil liquefaction. The use of hydraulic dredgers for backfilling operations is in general not recommended as it will increase the chance of pipeline float-up by producing a very high density soil/water mixture in the trench. Trenches can be made offshore with jet sleds, plows (ploughs), mechanical cutters or explosives. The choice of trenching equipment is of concern in sandy soil areas where trenches are required for stability and where natural trench backfilling does not occur. A jet sled will in general produce an unsatisfactory trench in such sandy areas as it creates a very wide trench which does not entirely eliminate the influence of currents and waves. Plows and mechanical cutters will produce steeper sided trenches in such areas and hence are preferred. A pipeline can also be lowered in sand by fluidising the sand around the pipe. The use of the fluidisation technique can be considered in shallow waterdepths if it can be ascertained that no clay is present. The existence of (unknown) clay lenses and debris (tree trunks) has produced some failures in the application of this technique.
2.2.3.2 Gravel or Rock Dumping Gravel can be dumped on the seafloor by three basic method: mass dumping, side dumping and dumping via a guide pipe - Mass dumping is carried out using split hopper barges. This method is basically uncontrolled as the entire barge load is dumped simultaneously. Due to excessive spreading of material in deeper water the method is restricted to shallow waters. - When dumping by means of a side dumping vessel, the load is dumped slowly and gradually. Greater control is achieved resulting in greater accuracy in deeper water. However to-date water depths have been limited to approximately 100 metres. - Dumping gravel via a guide pipe reduces the lateral spread and hence the volume of gravel required to be dumped. The velocity of the falling stones is only very slightly modified compared to side dumping as the stone's equilibrium velocity is reached very soon after leaving the pipe. This method has been successfully carried out at water depths of up to 155 metres.
The size of gravel for dumping is determined by the minimum size required to be stable at maximum current velocity, and the maximum size which produces acceptable impact forces on the pipe coating during dumping. To meet these requirements two layers of different grain sizes may sometimes be required. In general sizes from 20 to 200 millimetres are used to cover offshore pipelines in deep water, and up to 750 millimetres in shore approaches.
2.3
Field Welding and Inspection
2.3.1 2.3.1.1
Welding Codes and Standards
Acceptable codes and standards for welding of pipelines and related facilities are given in the relevant pipeline Design and Construction Codes such as ANSI B31.4, B31.8, etc. For certain project locations national or local requirements may dictate the application of a particular Standard The most common International Standards for construction welding of pipelines are API Std 1104, B54515 and DNV Rules for Submarine Pipeline Systems. Each standard lists the minimum requirements for: - weld procedure and welder qualification testing - preparation for welding - inspection, defect acceptance limits and repair, of pipe to pipe girth welds, pipe to fitting, and fitting to fitting welds. Pipeline systems, up to and including the receiver trap, are designed according to the pipeline code. Exceptionally, some on-plot pipeline facilities are designed to pressure vessel standards. In these cases, welding should be in accordance with the design standard. Recommendations on pipeline welding are given in International Institute of Welding (IIW) Document XIE/13/76 and some of the major welding consumable manufacturers issue handbooks/brochures giving specific advice on pipeline welding. Other less common areas of pipeline welding which require further consideration are; - hyperbaric welding - alternative or new welding processes - welding for sour conditions - hot tapping/live welding.
2.3.1.2 Welding Processes Some common welding processes are given below. The first abbreviation is according to the American Welding Society definition; the second represents the more common terminology for the same process. SMAW (MMA) Shielded Metal Arc Welding (Manual Metal Arc - stick electrode), e.g. typically used for girth welding.
GMAW (MIG/MAG) Gas Metal Arc Welding (Metal Inert Gas/Metal Active Gas, using Ar and CO2 respectively), e.g. as applied by the newer, mechanised girth welding systems. SAW Submerged Arc Welding, e.g. used for longitudinal pipe welding and double jointing. ERW/EIW welds.
Electric Resistance (Induction) Welding, e.g. as for ERW longitidunal
GTAW (TIG) Gas Tungsten Arc Welding (Tungsten Inert Gas), e.g. occasionally used for on-plot work and hyperbaric welding. FCAW (Flux Cored MIG) Flux Cored Arc Welding, e.g. generally restricted to shop fabrication.
2.3.1.3
Welding Consumables
Welding consumables (electrodes, wires, fluxes) are manufactured by a variety of companies from a multitude of component sources. Consumables should be of a type and brand previously approved by a Certification Authority as being in accordance with an international consumable specification, e.g. AWS 5.1-69 or BS639 for MMA electrodes. All consumables should be stored, handled and treated in accordance with the manufacturer's recommended procedures for that particular product. The choice of consumables is generally made by the contractor and reviewed/approved by the client. For manual metal arc welding of C-Mn steel pipelines types E6010, E7010 or E8010.G (cellulosic) or E7016/7018, E8016/ 8018 (low hydrogen) electrodes, as given in AWS 5.1/5.5, are most commonly applied. For onshore, mainline construction, MMA downhill welding using cellulosic electrodes is still the main process. Choice of consumable grade (E6010/ 7010, etc.) depends on matching the pipe steel grade. For offshore welding, mechanised short-arc CO2 (MAG) welding offers higher production rates and is increasingly used, e.g. CRC-Crose, H.C. Price, Saturn welding systems. For high restraint welds such as fittings, tie-ins etc. where alignment is more difficult the use of uphill welding using cellulosic or low hydrogen electrodes is recommended. For double jointing, then SAW/MAG/MMA or a combination of these processes can be applied, generally by roll-welding.
2.3.1.4
Welding Procedures
Welding procedures must be established according to the particular Standard being applied. The goal of the procedure should be to describe the method of working; define the welding parameters and the scope of validity, to ensure that the properties of the metal deposited are the same as those of the base material, and to report the test conditions and results. Standards like API Std 1104 (ch. 2) list the items considered as essential variables, e.g. pipe grade, diameter, electrode type, etc. A change in an essential variable will require requalification of the procedure. A review of all material certificates (pipe, fittings, consumables, etc.) should be made to ensure that essential variables are not changed, or to establish if alternative procedures should be qualified. Welding procedures should be qualified using the techniques, equipment, and method of working to be used on the line. Once the procedure is qualified, welders or welding machine operators should be qualified to use that procedure. Welders may qualify for part of the weld, e.g. fill/cap passes, or for the whole weld (API Std 1104, ch. 3).
2.3.1.5
Heat Treatment
One of the functions of the procedure qualification is to establish the requirements of any heat treatments. Three types of heat treatment are possible -warming, preheat and postheat (stress relief). The following recommendations are given by the IIW and BS4515: (a) Warming Warming the pipes before welding: - dries the weld preparation and burns off traces of grease, paint, etc., thus minimising porosity - improves the appearance of the root bead due to improved 'wetting' of the preparation by the weld pool. 0
For welding at ambient temperatures below + 10 C warming of the pipe ends to 0 approx. 50 C should be a routine procedure.
(b) Preheating Preheating serves to reduce the risk of hydrogen assisted underbead cracking by: - reducing the hardness of the first pass - assisting hydrogen diffusion out of the weld region - better distribution of shrinkage stresses.
As a general rule, preheating of large diameter/higher grade pipe/thicker wall pipe to 0 100-150 Cshould be the norm. Assistance in deriving preheat requirements can be obtained from BS4515-1984 and the nomogram shown in Figure 2.3-1, as follows:
Assume the following conditions: Heat input for single run weld Pipe thickness Pipe material carbon equivalent (all elements as % weight)
= = =
1.2 kJ/mm 25 mm 0.43
Using these values with Figure 2.3-1 it can be seen that underbead cracking will be 0 avoided at a preheating temperature of 60 C.
FIGURE 2.3-1 NOMOGRAM FOR PREHEATING REQUIREMENTS
(c) Stress Relief (Post-Welded Heat Treatment - PWHT) Stress relieving affects the residual stresses after welding and the hardness of the weld and heat affected zone. It is rarely applied to line welds under 25 mm WT. It may be required for welds in large, thick, asymmetrical fittings. (d) Sour Service Pipelines - PWHT For sour service pipelines, where a combination of high carbon equivalent, large wall thickness and low heat input process exist, e.g. mechanised CO2 welding, then it may be necessary to conduct PWHT to reduce HAZ hardness values. Generally the NACE MR-01-75 limit of Rc 22 (H.v. 248) is applied. In these cases the requirement for PWHT, method of application and resulting mechanical properties should be evaluated in detail.
2.3.1.6
Hot Tapping/Live Welding
Where total interruption of flow and line inerting is undesirable or impractical hot tapping, or live welding, provides an alternative maintenance/repair technique. The precise procedures to be employed will depend on a number of factors (medium, pressure, location, material, etc.) and must be fully tested and established. API PubI 2201 gives guidance on procedures for Hot Tap Welding and API RP 1107 covers recommended Pipeline Maintenance Welding Practices. Background data on techniques, welding, safety, etc. are available from industry sponsored development programmes. In view of safety requirements, and the limited post-weld inspection capabilities of Hot Tap Welding, aspects of procedure development and 100% surveillance during application are paramount.
2.3.1.7
Hyperbaric Welding
The welding techniques available for hyperbaric (increased pressure) welding are similar to those for surface welding, i.e. MMA basic low hydrogen, TIG or MIG/FCAW. Requirements for procedure and production welding are included in DNV rules together with welder qualification requirements. In addition to the weld and welder procedure qualification the inspection and weld repair procedures should be established. Efforts to optimise the inspection procedure (generally gamma radiography) should be made. Attention to general working procedures for removal of weight coating, pipe alignment, sealing, etc. will help minimise on-site problems.
2.3.2 2.3.2.1
Weld Inspection Requirements
The minimum inspection requirements, as a percentage of welds, are given in the Design/Construction Codes. Techniques and standard of inspection are covered in the pipeline welding standard. For high duty lines (offshore/ gas/sour service) 100% inspection is recommended.
2.3.2.2 Defects The various types of defects and levels of acceptance are given in the welding standards, e.g. API Std 1104 (ch. 6). As a general rule linear defects are most significant in terms of potential failure: - cracks; should be cut out. - surface breaking linear defects such as lack of root fusion/root penetration should be assessed according to their allowable lengths and repaired if excessive. - volumetric defects (slag, porosity etc.) are generally of less significance but indicate a poor level of workmanship (repair if excessive). Most welding standards are based on level of workmanship rather than an engineering basis. Over recent years alternative defect acceptance criteria based on Fracture Mechanics and Fitness for Purpose analysis have been devised. Before using this approach expert advice should be sought.
2.3.2.3
Inspection Techniques
(a) Visual Surveillance during construction ensures that the qualified procedure is being applied and helps minimise defects. Visual examination after welding helps to judge the standard of workmanship and indicates if additional inspection techniques are required to assist interpretation. (b) Radiography Both X-ray or gamma ray can be used although the superior image quality of X-ray is preferred and allows for better interpretation. For larger diameter pipes (> 0.25 m, 10 in.) an internal X-ray crawler, and panoramic technique, is used. For smaller diameters, or sit-on fittings, or limited weld numbers, external source double wall single image/double wall double image is used. Radiography is best suited for detecting volumetric defects (slag, porosity, lack of penetration, etc.). Given a good level of film quality and correct defect orientation then linear defects (cracks, lack of sidewall fusion, etc.) may be detected.
(c) Magnetic Particle Inspection (Dye Penetrant) Useful for detecting/confirming tight surface breaking defects (cracks). Interpretation is assisted by grinding the weld flush. (d) Ultrasonics Generally applied as a back up to the other techniques to confirm/detect suspected defects. Principally for buried volumetric defects, but a highly qualified operator may be able to detect surface defects as well.
2.3.2.4
Inspectors
Since inspectors are generally sub-contracted but have a major role in judging the overall weld quality, only qualified inspectors should be employed. A review of the inspectors qualifications and experience should be made prior to employment and ongoing checks made on their performance. Several levels of inspector are approved by welding inspector schemes. Their qualifications/approvals should be checked against the scheme requirements, e.g. ASNT, CSWIP, BGC-ERS (for pipelines).
2.3.3 Codes and Standards 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11.
API Std 1104, Standard for Welding Pipelines and Related Facilities BS4515, Specification for Field Welding of Carbon Steel Pipelines DNV, Rules for Submarine Pipeline Systems API RP 1107, Recommended Pipeline Maintenance Welding Practices API PubI 2201, Procedures for Welding or Hot Tapping on Equipment Containing Flammables IIW Doc. XIE/13/76, Recommendations on Pipeline Welding AWS A 3.0-69, Terms and Definitions AWS 5.1-69, Specification for Mild Steel Covered Arc-Welding Electrodes AWS 5.5-69, Specification for Low-Alloy Steel Covered Arc-Welding Electrodes AWS A5.18-79, Specification for Carbon Steel Filler Metals for Gas Shielded Arc Welding PTS 30.10.60.18, Welding of Metals
Note:
The above standards and Specifications are subject to periodic revision.
2.3.4
Common Pipeline Welding Terms
See AWS A3.0-69, Terms and Definitions, for a complete list of welding terms. Arc blow
-
Deflection of the welding arc due to magnetic forces (exceptionally may require degaussing).
Arc gouging
-
Using an arc to melt and remove metal such that a bevel or groove is formed.
Arc strikes
-
Spots outside the weld joint which have been caused by inadvertent contact of the electrode. Results in rapid quenching which can cause excessive hardness and microcracks (lightly dress and inspect - exceptionally may require cut out).
Back-gouging
-
Forming a bevel or groove on the inside of the weld prior to welding from that side.
Basic electrodes
-
Lime coated electrodes of the type E--16 or E-18.
Bead
-
A weld pass (may also mean root bead).
Bead welder
-
Welder qualified to make the root pass.
Blowhole
-
Gas pocket/cavity formed by entrapped gas.
Burn through
-
Excessive melt through, a hole in the root pass (caused by excessive current/poor electrode manipulation).
Buttering
-
Process of depositing weld metal on the pipe surface (fillet welds) or weld preparation (butt welds) to build up the surface(s) and allow the final gap to be bridged.
Cellulosic electrodes
-
Electrodes with a coating containing a high proportion of organic (cellulose) materials. Typically used for crosscountry pipeline welding. Electrodes exhibit a fierce, deep penetrating arc.
Compound bevel
-
Used on thicker pipe (± 20 mm and above) whereby a reduced angle on the outer part gives savings in weld metal and time.
Concave root
-
Internal root profile concave. Also termed suckback. Commonly caused by excessive rootgap.
Crater crack
-
Crater formed at end of weld bead which can contain small shrinkage cracks.
Heat-affected zone
-
Portion of the base metal which is not melted but whose properties or structure have been altered by the welding heat.
Hi-Lo
-
Misalignment of internal surfaces.
- root pass
-
First pass
- hot pass
-
Second pass (applied immediately after first pass, whilst still hot).
- filler passes
-
- cap
-
Passes:
Subsequent passes which 'fill up' the joint Final pass.
Piping
-
Linear shrinkage cavities in the root bead (also called wormhole).
Procedure qualification
-
The demonstration that welds made by a specific procedure can meet the prescribed standard.
Residual stresses
-
Stresses remaining as a result of thermal (or mechanical) effects.
Reverse polarity
-
Electrode positive, work negative.
Straight polarity
-
Electrode negative, work positive.
Root face
-
Land, landing edge.
Root gap/opening
-
Distance between root faces.
Slag inclusion
-
Non-metallic material entrapped in weld metal (often resulting from inadequate interpass cleaning).
Spatter
-
Small, easily detatched droplets of weld metal adjacent to weld.
Stove pipe welding
-
Technique for welding cross-country lines using cellulosic electrodes deposited vertically down.
Stringer bead
-
A weld bead deposited without significant weave or transverse oscillation (sometimes the root bead is referred to as the stringer bead).
Tack weld
-
A short weld made to hold parts together in good alignment until final welds are made.
Toe crack
-
Crack in the base metal adjacent to weld toe.
Underbead crack
-
Crack in HAZ, not always extending to surface of base metal.
Undercut
-
Groove melted into the base metal, adjacent to toe of the weld and left unfilled by weld metal.
Underfill
-
Depression on the cap or root surface extending below the surface.
Weave bead
-
Weld bead made with transverse oscillation.
Weldability
-
Capability of the base metal to be welded using normal procedure(s).
Wetting
-
The spreading and bonding of the liquid metal on the base material.
Welding - uphill
-
Welding progresses from bottom of pipe to top (vertical up). Welding progresses from top to bottom of pipe(vertical down). Welding with pipe axes vertical and welding pro gresses horizontally. Welding at one position (12 o'clock) whilst pipe is rotated.
- downhill
-
- horizontal
-
- roll
-
Note: The terms listed are for information - they do not imply recommended practices.
2.4
Hydrostatic Testing
Hydrostatic pressure testing is the accepted method of demonstrating the structural integrity of pipelines after the completion of construction. Prior to commencing the hydrostatic test the pipeline should have been adequately cleaned of construction debris and have successfully passed a gauging plate (preferably aluminium) of 95 percent minimum internal diameter undamaged through the section to be tested.
2.4.1 Testing Requirements The minimum requirements for testing are detailed in the relevant sections of the ANSI B31 .4 and B31.8 Codes and include test mediums other than water. Extreme caution should be exercised if testing with air or gas due to the enormous release of energy in the event of any pipeline failure. A strength test and a leak test (commonly at a lower pressure) may be conducted separately but these can be combined into a single test at the higher strength test pressure provided the necessary test procedures have been established. The minimum recommended duration for a strength test, leak test or combined strength/leak test is 24 hours. For very long pipeline test section lengths, particularly of the larger diameter, leak test durations should be increased after giving due consideration to the volumetric content of the test section, its location and to the detectability of possible small leaks. Variations in pressure during the strength test can be compensated for by the addition or removal of test water to maintain the correct pressure. For the leak test or combined leak/strength test it is not permissible to add water to the test section but water can be removed if pressure build-up is excessive. However any water that is removed should be measured and taken into account in the test evaluation. In general large pressure increases are unlikely to occur unless a significant proportion of the pipeline is exposed to ambient effects. In determining test section lengths, the profile of the pipeline and hence static head pressures are to be taken into account, such that the minimum requirements of the Code are maintained while not exceeding the maximum test pressure. The test pressure itself should not exceed the pipe mill hydrostatic tests (normally 95 percent SMYS based on nominal wall thickness for SIPM specification pipe). Heavier wall thickness pipe installed at special crossings, e.g. roads, can be tested at the same pressure and time as the main pipeline subject to any special provisions in the design or as required by local regulatory authorities. Valves included in a test section should be in the open position.
In some instances valves are used to segment a completed pipeline for testing purposes. In such cases it is necessary to ensure that the differential pressure across the valve is within its design allowance and that special provisions are made to monitor possible leakage across the valve. Scraper trap facilities included in any test section are to be tested to the same design code as the pipeline. Depending on the quality of the water to be used for hydrostatic testing and/or the length of time it is likely to remain in the pipeline after testing consideration should be given to protecting the pipeline by the addition of inhibitors, biocides and oxygen scavengers. Water analysis should be carried out to determine these requirements.
2.4.2 Test Equipment and Instrumentation Figure 2.4-1 illustrates the minimum requirements for test monitoring equipment.
FIGURE 2.4-1 TYPICAL SCHEMATIC OF TEST SECTION
Legend: PI = PR = DWT Tl1 Tl2 Tl3 M
= = = = =
pressure gauge, range 1½ times test pressure pressure recorder, range 1½ times test pressure recording time 24 hrs. min. dead weight tester, accuracy 0.01 bar, with current calibration certificate pipeskin temperature probes, sensitivity 0.1ºC intermediate pipeskin temperature probes (onshore pipelines only) ambient temperature measurement, sensitivity 0.5 ºC volumetric measurement device during pipeline pressurising i.e. flowmeter or pump stroke counter
2.4.3 Determination of Residual Air Volume in Pipeline The presence of residual air in the pipeline test section will influence the behaviour of the test section during the leak test hold period and will tend to disguise the presence of small leaks. It is necessary, therefore, to demonstrate that the quantity of residual air that may be present in a pipeline is below a minimum acceptable value prior to commencing the leak test hold period. The method for calculating the residual air volume is demonstrated in Figure 2.4-2. FIGURE 2.4-2 DETERMINATION OF RESIDUAL AIR VOLUME
Method: The air content shall be determined by constructing a pressure/volume plot from atmospheric pressure up to the linear section of the pressure volume plot curve and extrapolating back to the axis. The volume of the air shall then be read directly from the horizontal axis and compared with the total volume of the section. The maximum residual air contained in the system when filled with water shall not exceed 0.5% of the calculated volume of the system. If the air content is found to exceed this volume the section of pipeline shall be refilled. In special circumstances where the availability of water is very limited and it is not practical to refill the pipeline it is possible to proceed with the leak test. However due allowance for the presence of residual air should be included in the evaluation method and where necessary the leak test duration extended accordingly.
2.4.4 Hydrostatic Leak Test Evaluation Prior to commencing the leak test hold period, sufficient time should have been allowed for the pipeline and its contents to stabilise to the prevailing surrounding temperature. Once stabilised the leak test is commenced and, provided the pipeline does not contain a leak or excessive quantities of air, any variations in the test pressure over the hold period should be as a result of minor temperature fluctuations. To determine whether any pressure variations are a result of temperature fluctuation or whether a leak is present, the pressure/volume and temperature/volume relationship for the particular pipeline test section must be considered. For an infinitely long, fully restrained pipeline this relationship is governed by the following equations:
where: ∆V ∆p ∆T V D E t ν B γ α
3
= incremental volume, m = incremental pressure, bar 0 = incremental temperature, C 3 = pipeline fill volume, m = pipeline outside diameter, m = Youngs elastic modulus of steel, bar = pipe wall thickness, m = Poisson ratio, = bulk modulus of water, bar 0 -1 = volumetric expansion of water, C 0 -1 = linear expansion of steels, C
By comparison of the incremental volume changes due to pressure and temperature fluctuations over the leak test hold period, the acceptability of the test can be established. In the event of there being any doubt after evaluation of the hold period, the test should be extended until such time as the acceptability is adequately demonstrated or alternatively the presence of a leak is confirmed. In the latter event the leak has to be located and removed from the pipeline prior to retesting. For reference values of the bulk modulus and volumetric expansion of both fresh water and sea water are given in Figures 2.4-3 to 6.
FIGURE 2.4-3 BULK MODULUS OF FRESH WATER AS A FUNCTION OF PRESSURE AND TEMPERATURE
FIGURE 2.4-4 BULK MODULUS OF SEA WATER AS A FUNCTION OF PRESSURE AND TEMPERATURE
FIGURE 2.4-5 VOLUMETRIC EXPANSION COEEFICIENT OF FRESH WATER AS A FUNCTIONAL OF PRESSURE AND TEMPERATURE
FIGURE 2.4-6 VOLUMETRIC EXPANSION COEEFICIENT OF SEA WATER AS A FUNCTIONAL OF PRESSURE AND TEMPERATURE
2.4.5 Location of Leaks During Hydrostatic Testing While the incidence of leakages/failures during hydrostatic testing is relatively low, its occurrence can cause considerable delays and additional costs. To minimise potential delay and cost it is prudent to formulate a contingency plan at an early stage in the project which can be swiftly put into action if required. Such a contingency plan could, for example, include the addition of a dye to the test water in an offshore pipeline so that in the event of a leak occurring it would not become necessary to refill the pipeline with water containing dye. A variety of techniques are available for locating leaks both in onshore and offshore pipelines. Table 2.4-1 summarises the presently available techniques together with some pertinent information.
Table 2.4-1 Summary of methods for the location of leaks during hydrostatic testing
2.5 2.5.1
Cleaning/Drying/Pigging Cleaning
Pipelines built for the transportation of liquid or gaseous hydrocarbons normally require thorough cleaning to achieve the following objectives: (a) To reduce the risk of corrosion induced by the presence of debris. (b) To protect downstream plant facilities from fouling. (c) To maintain the transport efficiency and the quality of the product. Table 2.5-1 summarises the main pipeline cleaning methods and their application to pipelines at different stages in their lifetime.
Table 2.5-1 Cleaning applications/methods
2.5.1.1
Cleaning Methods
Depending on the operational service and the actual condition of the pipeline an appropriate cleaning method has to be selected for the degree of cleanliness required. (a) Water Flush This entails flushing with water at velocities above 3 m/s with the aim of washing out loose debris. If sea water is used as the primary flushing agent, fresh water must be used subsequently to flush out the residual salt water. The method is, however, limited by the available pumping and/or storage and disposal facilities.
(b) Scraping/Brush Pigging In this method a number of cup pigs equipped with either brushes or scraper blades, or foam pigs with wire brushes, are driven through the line propelled by water or air. By this method loose debris and loosely attached rust and mill scale can be effectively removed. Removal of hard or tightly adhering deposits or scale will require the use of special tools or a chemical cleaning programme. To reduce a risk of pile build-up of debris ahead of a tool, pigs should first be run with open bypass holes. This allows the propellant to pass through the pig.
(c) Gel Plug This is a new method developed by Shell Development Company, USA, capable of removing relatively large quantities of loose debris from a pipeline system. The method can be particularly attractive for long distance trunk-lines when an unacceptably high risk of line blockage exists if conventional pigs are used, or when a water flush is ruled out for technical or economic reasons. A gel cleaning train consists of batches of visco-elastic and visco-plastic gel interspaced with separation pigs (see Figure 2.5-1). The train is propelled by air, water or gas at a controlled speed of approx. 0.3 m/s. In principle, the separation pig forces the fluid in the vicinity of the pipe wall to pick up loose debris, and move it into the central plug flow region, where it is then carried forward and distributed in the gel batch and eventually removed from the pipeline. A gel does not possess abrasive or chemical cleaning properties. It should be noted that a gel cleaning train must be specially designed for a particular application (Central Offices to advise). (See Figure 2.5-1.)
FIGURE 2.5-1 GEL CLEANING TRAIN
(d) Special Cleaning Methods known for cleaning of pipelines to bare metal conditions required for a particular service or for internal coating preparation are; - the shot/grit blast process - chemical cleaning. The first method is restricted to short distance pipelines (max. length depends on diameter) whilst in-situ chemical cleaning, using batches of a specified acid concentration followed by a rinsing cycle, can be designed for longer distance pipelines but requires specialised contractors. The requirements for and the application of internal protective coatings are described in 1.3.7.
2.5.1.2
Guidelines on Cleaning Methods
From the moment a pipe is manufactured until it becomes operational as part of an integrated pipeline system, it is of great importance to keep the pipes as clean and dry as possible. Rust and debris will absorb and retain water and even fully treated sweet water remaining in debris may adversely affect the condition of the line. It is therefore essential that the protection of pipe and its cleaning is implemented by appropriate contractual provisions during transport, storage and construction, and by sound supervision and inspection practices. Prior to the execution of any cleaning operation it is advisable to make provisions enabling reliable control of the cleaning pig runs by means of pressure and flow control. Further, it must be ensured that the vendors specifications are adhered to.
The effectiveness of debris removal is difficult to measure and the specification of a 'degree of cleanliness' is even more difficult to establish. It is advisable to monitor the condition of a pipeline when filled with inhibited water over a length of time. This can be achieved by the use of coupons, made from pipe material and by keeping the coupons under the same conditions as the pipeline. The specification of storage, pumping, fluid treatment, and disposal facilities for a water flush, a gel cleaning or any special cleaning operation, requires special investigation or advice from Central Offices (Pipelines Section) when such operations are contemplated. The application of cleaning methods during operation are described in more detail in 3.5.1 (Routine and Special Operations).
2.5.2 Drying After construction and hydrostatic testing of pipelines it is sometimes necessary to dry the pipeline completely prior to putting it into service. This may be required to prevent corrosion or hydrate formation in the pipeline or to comply with stringent product specification requirements. The drying process is to be preceded by thorough cleaning and dewatering to ensure that no debris and no pools of water are left in the pipeline. Under certain conditions it may be possible that deficiencies in dryness can be compensated for by inhibition (see 3.3.5 and 3.5.2).
2.5.2.1
Drying Methods
The principles and the limitations of two currently recommended drying methods are described below. (a) Air/Gas Drying This method relies on the absorption of the remaining water film into dry air or dry gas. This is commonly achieved by passing dry air or dry gas, at low pressure, through the pipeline in conjunction with foam pigs until the desired degree of dryness has been achieved. The application of this method in long pipelines (i.e. 25km or longer) is limited by the effectiveness of the foam pigs to remove all the fine rust particles. As a 0 result the drying time to achieve a dryness level below - 10 C water dew point may become impractically long. (b) Vacuum Drying This method relies on the vaporisation of the remaining water film in the pipeline and the evacuation of the water vapour from the pipeline.
The vaporisation is effected by lowering the pressure in the pipeline to a vacuum level at which the water will boil at a temperature slightly lower than the surrounding temperature. Application of this method is for practical reasons limited to diameters above, say, 10 inches, because in smaller diameters the high pipeline pressure drop affects the pump mass flow capacity resulting in long drying times. In cold climates the method is limited because the low-temperature conditions lead to low water boiling pressure and subsequent low vapour density which reduces the mass flow capacity of the pump, again resulting in long drying times.
2.5.2.2
Equipment/Utility Requirements
Air/Gas Drying - Air compressors or gas flow of sufficiently large capacity to propel pigs at a velocity of 1-2 m/s. 0
- Dryers capable of drying the air or gas to a water dew point of at least 50 C. - Polyurethane foam pigs. - Pressure and dew point measuring instruments. - Inert dry gas supply to purge line after an air drying operation. - Flow instrumentation. Vacuum Drying - Vacuum pumps, e.g. Roots blower, liquid ring pumps, etc., and/or vacuum ejectors of sufficiently large capacity to evacuate line to boil-off level and to accomplish the specified dryness within a predetermined time interval. - Air or steam supply for the ejector units. - Cooling water supply for condensors and vacuum pumps when applicable. - Flow, pressure and dew point measurement instruments. - Inert gas supply to check the dryness and to fill the line if necessary.
2.5.2.3
Guidelines on Drying Methods
The most appropriate method depends on many factors, including the parameters of the pipeline to be dried, its location, the degree of dryness required, logistics, timing, economics, etc. The degree of dryness depends upon the operational service whereby (as a 'rule of thumb') no corrosion is expected if the line is dried to a water dew point at 0 atmospheric pressure approximately 10 C below the water dew point of the fluid at the design pressure (specified dew point).
The success of a drying operation depends largely on the success in removing residual pools of water from the line during the dewatering operation. To accomplish this, a number of pigs are passed through the line to pre-condition the line prior to the drying cycle. The drying time should be estimated as accurately as possible prior to starting the drying operation. The accuracy depends largely on the estimate of the water film left in the line after dewatering, assuming that all loose debris has been removed during the construction cleaning operation (see 2.5.1.1) and that no pools of water have been left in the line (see 2.5.2). Some of the factors influencing the wafer film are: - condition of the pipewall (millscale, rust and effective roughness) - profile and length of line, and their influence on pigging - effectiveness of pigging. As a 'rule of thumb', under average conditions, it can be assumed that a liquid film of 0.1 mm thickness is left in a clean pipeline after dewatering. In order to confirm the success of the drying operation, the pipeline must be purged with at least one line fill of a dry gaseous medium with a dew point equal to the specified dew point. If the dew point (adjusted for pressure) at the outlet remains equal to the dew point at the inlet, the line can be considered to have been dried to the required dew point.
2.5.3 Pigging The use of pigs and spheres in pipeline operation has become a well accepted procedure. However, the full extent of the advantages that their use may provide is not always recognised. This may be due to various reasons such as inexperience in pig operation, and unfamiliarity with the recent and fast growing development of new applications which form part of routine operation in other pipelines or plants. This Section summarises pig operation in pipelines. The various field applications, the different types of pigs available together with their characteristics, and the conditions required for correct operation are described so as to provide guidelines for each application. This Section does not fulfil the function of a detailed handbook (such as Ref. 1). The reader is therefore recommended to contact a reputable manufacturer and/or Central Offices, The Hague, when specific advice is required.
Notes: 1. When ever the word 'pig' is used here under without any special indication, it refers to all types of pigs and spheres. 2. Cup types are not bi-directional and should not be used if there is any likelihood that they may get stuck.
2.5.3.1
Application and Types of Pigs
For the various applications shown the following types of pigs are used: (a)For pipeline cleaning see Table 2.5-2. Cup Types Pigs having a steel body fitted with cups and either hardened steel brushes, to remove rust, or polyurethane scrapers to remove wax deposits. Foam Types Made of hard polyurethane foam, covered with abrasive coating or wirebrush bands to remove rust. (b) For gauging product displacement or separation see Table 2.5-3. Cup Types Pigs having a steel body and fitted with two or more cups. Type 1 gauging pig: used during construction to check the pipeline for buckles or dents. Type 2 displacement/separation pig: primarily intended for use in multi-bend pipelines to maintain a seal between batches of different liquids or between gas/liquid phases. Disc Types Pigs having a steel body and fitted with four or more diaphragm discs to allow bidirectional use, especially during filling and dewatering operations before, during and after hydrostatic testing, when there is a chance that a cup-pig may get stuck. Spheres Spherical moulded tools made of polyurethane or neoprene (of which the larger sizes are inflatable); mainly used for product separation, and controlling liquid hold-up.
Table 2.5-2 Cleaning pigs
Table 2.5-3 Gauging pig and displacement/separation pigs (spheres)
(c)For pipeline swabbing and drying see Table 2.5-4. Foam Types Pigs made of plain soft polyurethane foam used for water absorption in swabbing and drying service.
Table 2.5-4 Swabbing/drying pigs
(d) To carry instruments: See 3.4.3 (Intelligent Pigs) for details on application.
2.5.3.2
Launching and Receiving Traps
A typical procedure which allows the easy insertion into, and withdrawal of pigs from, a pipeline without shutting down the whole line is described in Section 2.6 of Vol.6. A basic line diagram is shown in Figure 2.5-2. Launching and receiving traps consist of a barrel made of steel pipe at least 50 mm (2 in.) larger in diameter than the pig and of sufficient length to contain the required number of pigs. Additionally, the receiving trap must be sized for any expected accumulation of solid material or wax. The traps are usually equipped with quick closures, while their mechanical design must meet the applicable pipeline Design Code requirements. Vents, drains, balance lines, door safety mechanisms, etc are required on the traps, together with double valves in some instances.
The safety aspects of these requirements are discussed in EP 55000-21 and detailed requirements will be included in a planned Group standard called "Design of pig trap systems for transmission pipelines".
The launching and receiving barrels may be inclined to facilitate both the introduction and the retrieval of the pig.
Note. Mechanics handling gear is usually provided for larger size pig launching and receiving traps. The use of 'intelligent pigs' may require barrel lengths longer than those normally required for conventional pigging (see 1.6).
FIGURE 2.5-2 DIAGRAM OF A TYPICAL LAUNCHING/RECEIVING TRAP
2.5.3.3
Ancillary Equipment
(a) Intermediate Traps An intermediate trap is a combination of a receiving and launching trap. Modern methods for bypassing pumping stations, however, no longer require the removal of the pig from the line and the operation can be fully automated. On reaching the pumping station, the pig is diverted into the bypass section, while the main flow passes through the pumps. The pig is re-injected into the main flow at the pumping station outlet. (b) Pig Signallers Pig signallers are usually of the mechanical type. The plunger type is preferred and should be of the type that can be serviced under line pressure. (c) Pig Locators Pig locators are used either to follow the course of the pig in the pipeline from the outside or to detect the location of a pig jammed in the line. (d) Tees The maximum diameter branch opening for each pig size is indicated in manufacturers' catalogues. Guide bars are required to prevent jamming of the pig in the branch opening if the branch line exceeds a certain diameter. Furthermore, in the case of spheres, construction should be such that inadvertent lodging of spheres is prevented. Ready-made tees for pig or sphere duties are available from manufacturers. (e) Radii of Bends Bends in pipelines which have to be pigged or scraped regularly without undue restriction to flow should have radii equal to, but preferably more than, three times the pipe diameter especially when designed for use of intelligent pigs. In the case of low velocities or in cases where space is at a premium, bends with radii 1½ times the pipe diameter can be negotiated by most pigs (but rarely intelligent pigs) and all spheres. The advice of the selected manufacturer should be sought on this matter. Mitred bends should not be used. (f) Valves For valve types which are suitable for pigging/scraping, reference should be made to valve catalogues. Valves must be of the full-bore type.
3. OPERATIONS
3.1
Commissioning
The commissioning of a pipeline system commences when the pipeline is connected 10 the upstream and downstream production facilities and considered ready for its operational duty, i.e.: - Construction is completed and checked in accordance with design. - Pipeline is preconditioned to a specified degree of cleanliness and dryness to prevent unacceptable corrosion or hydrate formation during commissioning. - Pipeline is filled with a suitable medium which can be safely displaced by the transport medium. - Pipeline operating control system is tested for its operability. During the commissioning period, the performance of the pipeline system will have to be checked, against realistic predetermined initial operating conditions. Additionally, there are certain aspects related to the operation of the liquid product or gas pipelines respectively, which will require verification during the initial start-up period and subsequently as outlined below.
3.1.1 Liquid Product Pipelines These pipelines are designed to transport liquid hydrocarbons or chemical feedstocks. Monitoring of the following aspects will be important to ensure that no hydrate formation or corrosion takes place. (a) (b) (c) (d) (e) (f)
Product contamination, sediments or deposits and their removal. Pressure, flow, temperature and moisture content. Presence of corrosive components in combination with presence of free water. Corrosion rate. Effectiveness of corrosion control programme when applied. General condition of the pipeline system.
3.1.2 Gas Pipelines Pipelines designed to transport natural gas can be subdivided into: - Sweet gas Gas which may or may not contain CO2 but no H2S.
- Sour gas Gas which contains H2S (see HSE in Volume 1) with or without CO2. Pipelines transporting one of these gases will be sensitive to corrosion and! or hydrate formation if free water is present. Therefore it is necessary to monitor the following aspects: (a) (b) (c) (d) (e) (f)
Dryness of gas produced into and out of the pipeline. Pressure, flow and temperature. Corrosion rate and other possible corrosion aspects. Liquid and/or sediment build up and their removal. Effectiveness of corrosion control programme when applied. General condition of the pipeline system.
3.2
Pipeline Monitoring and Control
3.2.1 Process and Instrument Diagram This section gives a general overview of a pipeline system via a simplified Process and Instrument Diagram (Figure 3.2-1). The types of instrumentation in a pipeline system can comprise the following: (a) Flow, pressure, temperature measurements (b) Quality measurements (c) Safety systems (d) Supervisory Control and Data Acquisition (SCADA) systems. (e) Leak detection systems. Except for (e), all the above types are covered in Volume 9, to which reference should be made for more detailed information.
FIGURE 3.2-1 SIMPLIFIED PROCESS AND INSTRUMENT DIAGRAM
3.2.2
Leak Detection
Although in some countries certain methods of leak detection may be required by law, in general they are installed for the following reasons: - safety, with particular regard to products transported - environmental protection product conservation minimisation of third party compensations minimisation of loss to users. Different methods are available for the detection of leaks of which an overview is given in Table 3.2-1. Table 3.2-I Leak detection methods
It should be noted that the figures given in Table 3.2-1 are indicative only and basically relate to cross-country oil pipeline experience. In general, the detectability of leaks decreases with increasing compressibility of the fluid transported.
3.3
Internal Corrosion and Corrosion Monitoring
This Section gives a brief overview of internal corrosion monitoring and control (see Volume 9 for more detailed information). External corrosion and corrosion protection are covered in Section 1.3.
3.3.1 Internal Corrosion, General The potential for corrosion almost always exists. Its effects can be minimised and delayed through good design, monitoring, and a knowledge of corrosion processes and protection. Corrosion in carbon steel pipelines can take place when the following agents occur (singly or in combination): WATER (always required) and
- CO2 (sweet corrosion) - H2S (sour corrosion) - O2 (oxygen corrosion)
The severity of corrosion is controlled by the physical variables of the environment (in addition to the concentration of the corrosive agents), i.e.: temperature, pressure, conductivity, pH and fluid velocity.
The severity is modified by mill scale, stresses (constant, cyclic), heat treatment, combinations of metals, etc.
3.3.2 Internal Corrosion and Control at the Design Stage Corrosion control must always start at the design stage and be based on the anticipated presence of water in combination with the possible presence of any or all of the following: H2S, CO2, O2, chlorides (especially with stainless steels), other salts and debris. Whatever measures are chosen, careful monitoring is required to check their effectiveness. The following methods are available to remove water from liquids and gases (after separation): (a) Liquid - separator - electrostatic precipitator. (b) Gas - absorption with liquid desiccants, e.g. glycol in a continuous system
- adsorption with solid desiccants (alumina, silica gel, silica-alumina beds, molecular sieves) all in cyclic, regenerative systems - expansion refrigeration. Further possibilities for dealing with internal corrosion of pipelines are: - Oxygen scavenging (typically for waterlines) - Chemical inhibition - Chemical control (removal of dissolved gases) - pH adjustment 0 - Internal coating (limited to less than 80 bar and less than 110 C, limited lifetime) - Use of corrosion-resistant materials or linings (metallic or non-metallic) - Stress, shock load and vibration reduction - Elimination of sharp bends and high turbulence - Corrosion allowance on wall thickness (only where uniform corrosion can be predicted) - Regular removal of debris and deposits by pigging (see 2.5.3).
3.3.3 Corrosion Monitoring Corrosion monitoring is essential, and adequate provision should be made for this at the design stage of any project. An overall picture of the rate and types of corrosion that are occurring is achieved by considering the combination of results of the appropriate available methods, i.e.: - corroding specimens • coupons • probes • test spools - electrical/electrochemical methods - linear polarisation instruments - hydrogen patch probes - chemical methods • inhibitor tests • corrosion product analysis • bacteria counts • dissolved iron counts - physical methods • radiography • ultrasonics • eddy current (see 3.4.3, internal inspection tools)
3.3.4 Dryness Monitoring Where it is the intention to minimise pipeline corrosion by drying the medium to be transported, it is essential that reliable monitoring is carried out of the amount of water present (for gases, this is dew point measurement). 100% back-up facilities and frequent (weekly) instrument calibration is needed. Continuous measurement is preferred. Particular care is needed to prevent wet upsets during start-ups, shutdowns and transition periods. Appropriate remedial action such as inhibition, diverting of the medium away from the pipeline, or recycling can be initiated by dryness measurements. Note that in sour service, H2S can combine with iron oxides (rust, mill scale, etc.) to produce sulphur and water.
3.3.5 Corrosion Prevention Methods As discussed previously in this Section, corrosion prevention starts at the design stage and consists of choice of suitable material (see 1.2), coatings and cathodic protection (see 1.3) and inhibition. Inhibitors can be grouped according to the way in which they work as follows: - Barrier Layer Formers - Neutralising Inhibitors - Scavengers (Oxygen) - Miscellaneous (such as biocides and scale inhibitors) Inhibitors should: - reduce corrosion significantly and (in sour service) at the same time reduce hydrogen absorption. - be soluble in a solvent present in or compatible with the medium to be transported. - be compatible with downstream operations, e.g., should not lead to foaming in glycol plants or present toxicity problems in effluents. 0 - be stable throughout the range of operating temperatures (not exceeding160 C). - not form a stable emulsion in oil/water systems. Specialist advice and laboratory screening are recommended to determine the appropriate inhibitor. A suitable application method in the field is best decided from a combination of the manufacturer's recommendations and the results of testing.
Inhibitors can be injected continuously to mix with the medium or applied in slugs. In a batch or slug, the inhibitor is mixed with a carrier and sent down the pipeline between two spheres or cupped pigs. The test results will give information about concentrations and batching frequency to be used. It is important that pipelines to be protected are well-cleaned, as inhibitors are ineffective in the presence of dirt and/or scale which allows corrosion to take place beneath it. Cleaning pigs will disturb a film of inhibitor on the pipewall, so such operations should precede inhibition treatment. To limit turbulence caused by weld upsets, and consequent localised lack of inhibition film, weld upsets on the inside of the pipe should be limited to 0.5 mm or less. This can be expensive, but should be done when the risk of corrosion from this source is high. The effectiveness of inhibitors is measured by reduced corrosion rates being observed, so good record-keeping is important in order to obtain protection at minimum cost. Inhibitor slugs or batches should coat the whole internal surface of the pipe, and measurement by the neutron back-scattering technique can determine if the slug or batch covers the whole cross-sectional area of the pipeline. Where continuous injection is carried out, the upstream and downstream inhibitor concentrations should be monitored to ensure that inhibitor is being steadily received at the end of the pipeline.
3.4
Pipeline Inspection
3.4.1 Pipeline Failures Although pipelines are considered as the safest means of bulk transportation for hydrocarbons when compared with others, e.g. rail, road or barge, some failures do occur which result in spillages. FIGURE 3.4-1 PERFORMANCE OF OIL PIPELINES IN WESTERN EUROPE AND IN THE NORTH SEA
Figure 3.4-1 shows a graphical presentation reported by QONCAWE (The Oil Companies European Organisation for Environmental and Health Protection, Brussels) and UKOGA (United kingdom Oil Operations Association) on the causes of incidents relating to pipelines, in Western Europe and the North Sea respectively. It can be seen from the graphs that the majority of incidents can be attributed to three major categories, i.e. mechanical failure, corrosion and third party activity external impact.
3.4.2 Pipeline Inspection and Monitoring Methods The main causes of incidents are briefly discussed below together with measures to identify and locate potential leaks and reduce the frequency and severity of their occurrence.
3.4.2.1
Third Party Activities
Pipeline surveillance by flying or walking the route are the principal visual methods in use to obtain early information on activities potentially hazardous to the pipeline, e.g. civil construction near or on the pipeline way-leave, etc. The frequency of visual inspection should be based on local requirements. In certain areas the so-called 'one-call system' has been introduced whereby the contractor planning to perform works in a certain location may call one telephone number. In other areas the prospective contractor is required by local law, before performing the works, to consult a central body where plans and drawings of all pipelines in the area are kept up-to-date.
3.4.2.2
Corrosion
Prevention of external corrosion commences with the design and installation of the appropriate pipeline coating and cathodic protection (CP) system (see 1.3.6 and 3.4.2.4). If there is a risk of internal corrosion, this can be combatted by appropriate operational methods, e.g. regular pigging of the pipeline by sending spheres or pigs through the line to prevent settling out of water at low points along the route, and/or in certain cases the application of appropriate corrosion inhibitors (see 3.3). The occurence of internal/external corrosion may be determined by means of special metal loss inspection tools sent through the pipeline with the medium acting as propelling agent (for a survey of commercially available inspection tools see 3.4.3).
Examples of intelligent pigs are: Tuboscope/ Linalog British Gas/On-Line Inspection Tool (OLI) Pipetronix/ Ultrascan The first two operate on the principle of magnetic flux leakage whilst the last one uses ultrasonics. The Linalog tool is shown in Figure 3.4-2. The metal loss measurements are recorded in the tool for off-line processing and evaluation. The data can be evaluated visually, as shown in Figure 3.4-3, or by computer techniques FIGURE 3.4-2 THE 'LINALOG' INSPECTION TOOL
FIGURE 3.4-3 THE LINALOG RECORD
3.4.2.3
Mechanical
Sound pipeline design including proper material selection, manufacturing quality assurance, inspection and testing of pipes, valves, fittings, pumps etc., together with proven construction techniques, rigid supervision, X-ray testing of welds and hydrostatic testing are essential procedures for minimising the occurrence of mechanical failures during operation. On-line inspection of the mechanical condition of the pipeline can be done by means of Inspection tools, e.g. the Kaliper Pig and the Gee-pig (see 3.4.3). The Kaliper Pig's rear cup contains a finger mechanism which detects deformations. These deformations are recorded inside a sealed instrument container within the Kaliper Pig for retrieval and analysis. As an example a Kaliper run record is shown in Figure 3.4-4. FIGURE 3.4-4 KALIPER RUN RECORD
3.4.2.4
Inspection of Cathodic Protection (CP) Systems on Pipelines
(a) Onshore (buried) For major lines which are normally protected by impressed current the following inspection procedure is recommended: (b) Routine Inspection Potential measurement via access posts along the right-of-way: - Preferred reference electrode: Copper - Copper sulphate with porous end plug. Ensure contact by watering soil. - Voltmeter input impedance: > 1 MΩ. For desert areas (high soil resistivity) 100 MΩ is recommended. For optimum measurement the use of a 'compensator' is to be preferred. Current-off technique should be used when possible.
(ii) Intensive Inspection This should be carried out 1 year after commissioning and repeated every 5 years. The inspection should cover close-to-pipe potentials between scheduled access posts (see Figure 3.4-5). FIGURE 3.4-5 INTENSIVE CATHODIC PROTECTION INSPECTION
(b) Offshore Options (in order of decreasing ease of application): - Diver measurement at selected spots. - Permanent monitoring via acoustic telemetry system. - Survey via wire and contact to pipe with diver or ROV. - Remote electrode method: one reference electrode towed over pipe, one remote electrode at surface: gives potential profile. - Potential gradient measurement: Measures current flowing through seawater to pipe (or out of anode).
3.4.3 Intelligent Pigs There are several commercially available intelligent pigs, as shown in Table 3.4-1. SIPM, in conjunction with SIRM, is continually assessing the performance of available tools. Status report EP 88-2280 was the last formal report on these tools but a replacement EP report, 'Status Report on On-line Inspection Tools', will be issued in 1991. In most cases intensive line preparation is required before intelligent pigs can be applied. The order of sequence is as follows: - Ensure that all bends can be negotiated by intelligent pig - Install launching and receiving facilities (if required) - Remove any known obstructions - Clean pipeline - Run geometry inspection pig, e.g. T.D. Williamson Kaliper
-
Remove any detected dents that can obstruct intelligent pig Run dummy intelligent pig with gauging plate Run intelligent pig.
Table 3.4-1 Types of commercially available intelligent pigs
3.5
Routine and Special Operations
During the lifetime of a pipeline, conditions may develop which will require routine and/or special operational measures in order to maintain the Integrity of the pipeline system, or to warrant its efficient, reliable and economic operation. Such conditions may be due to the following: -
corrosivity of the fluid hydrate formation formation of inorganic deposits formation of wax deposits condensation or carry-over of water ('wet upset') product contamination.
Operating and maintenance procedures should ensure that operating parameters and line status are monitored and analysed as a matter of routine and that information obtained from inspection surveys (see 3.4) and corrosion monitoring exercises (see 3.3.3) is evaluated. This will enable early identification of significant changes and timely implementation of corrective action. The methods available to maintain a pipeline system in an optimum condition are: - cleaning - inhibition - liquid removal - product separation. The application of each method depends on many factors, including amongst others the characteristics of the product and the existing condition of the pipeline.
3.5.1 Cleaning The build-up of corrosion products or other deposits will gradually increase the internal roughness of the pipeline thereby reducing the flow and increasing the head loss. Routine cleaning during operation is therefore of vital importance to maintain the pipeline in an optimum condition, i.e.: - to prevent loss of efficiency - to reduce the risk of corrosion - to ensure effectiveness of inspection tool survey - to facilitate effective corrosion inhibition. Some cleaning methods for application during operation are described in 2.5.1.1.
3.5.2 Inhibition Inhibition of pipelines during operation is considered as the second line of defence to control internal corrosion. The primary measure remains the control of the dryness of the product transported. The reasons for an inhibition programme and the various types of inhibitors applied are described in 3.3.5.
3.5.3 Liquid Removal Pipelines transporting liquids, gas or a combination of both, may have to be operated under conditions whereby other fluids may settle out of the transported medium. This condition may be the flow velocity being insufficient for entrainment, or an intermittent flow pattern or pressure/temperature related solubility changes. The fluids, which settle out, may upset flow conditions, cause hydrate formation and/or may be corrosive. The removal of such fluids is therefore essential for the proper operation of the pipeline. Under some conditions removal can be effected without the use of pigs (if the flow velocity is sufficient to maintain entrainment, e.g. for oil lines water pick up is at velocities in the region of 1 m/s). However under conditions where settlement is expected, periodic pigging or sphering must be applied to ensure maximum transport efficiency.
3.5.4 Product Separation To prevent contamination of products in multi-product pipeline systems the liquids transferred in succession are commonly separated by spheres. The arriving batches at the end of each transfer can be easily routed into proper tankage when pig-passage signallers, situated some distance upstream of the terminal, give an early warning of the arrival of each batch.
3.6 3.6.1
Pipeline Repair Safety
Execution of effective and safe repair work requires careful planning. In case of a pipeline rupture involving escape of flammable and toxic hydrocarbon gases or liquids, emergency procedures should be followed aiming at avoiding risks of personnel injuries, and minimising material and environmental damage (see 3.6.2). Pre-planning and special training is considered good practice in order to ensure that all personnel involved, Company as well as contractors, are familiar with measures to establish and maintain safe working and environmental conditions at the repair site, to be aware of and avoid potentially hazardous situations, know the resources available (manpower, equipment, material) and the responsibilities and reporting relationships within the emergency organisation. Safety measures will be required after a pipeline rupture mostly because of the risk of fire or explosion and sometime because of toxic or other hazards. Such measures fall outside the scope of this Handbook. However, it is strongly recommended that all personnel involved in implementing repairs familiarise themselves with relevant safety manuals (see also 3.6.2). Repair work on pipelines with exposure to hydrocarbons requires hot work permits, to be issued by the responsible operating department's representative.
3.6.2 Emergency Procedures The development of emergency procedures is recommended covering: (a) Pipeline shut-down (b) Leak search (c) Organisational procedures for handling emergencies including notification of authorities (if required) (d) Safety (e) Repair methods (f) Re-commisioning, if required, and start-up. The procedures concerning repair methods should cover a range of techniques in order to cope with varying conditions of leak sizes. Options may include construction techniques for swamp, dry land, habitated areas or beach area, shallow and deep water (offshore).
The availability of materials should be analysed and where necessary pipe, connectors, fittings, clamps and special repair equipment should be procured and kept in working order in separate storage. It may be necessary to have standby contract arrangements with contractors to ensure availability of construction equipment for emergency repatrs
The availability of emergency procedures will avoid or reduce confusion and consequently minimise repair time.
3.6.3 Temporary Repair Temporary repairs are often made aiming at maintaining flow in the pipeline, with reduced pressure if necessary, while the final repair can be planned and implemented in due course. Various types of clamps (PLIDCO, etc.) are available for temporary repair or for repair of minor leaks in pipelines. These clamps will in most cases only re-establish the pressure holding capability of the pipeline. If the pipeline is experiencing bending moments and/or tension at the leak point it may be necessary to use a clamp which has the capability to transmit such forces adequately, e.g. Hydrotech and Gripper. Small cracks should be mapped using ultrasonic equipment and drilled at the crack tip in order to prevent further crack growth. See also the split sleeve method described in Section 3.6.4.1 below. 3.6.4 Permanent Repair 3.6.4.1 In-Service Repair A well proven method of in-service repair is by welding full encirclement split sleeves over the defective section of pipe. This method is however generally only suitable for external damage or defects. Internal defects, normally corrosion, can be expected to worsen and result in product leaking into the sleeve. Although the sleeve may be fully pressure containing, the integrity of the fillet welds and the sleeve itself is likely to be in doubt since the annulus will become filled with stagnant product and any water or debris drop-out. This method may however be useful as a short-term temporary repair of internal defects. The sleeves can be of two types: fillet-welded ends and non-welded ends. The former is generally the preferred method for long term integrity but it does involve 'hot' working. The beneficial effect of filling external defects, such as gouges and dents, with epoxy filler prior to installing the sleeves is well established.
3.6.4.2
Major Repair
Major repair work, e.g. replacement of pipe sections or pipeline components such as valves, requires shut-down of operations, depressurising, and evacuation of the pipe section to be repaired. Some typical aspects of major repair jobs are mentioned below: Planning: Careful planning aims at limiting risks involved as well as controlling costs incurred by major repair work and loss of production. Again, safety and protection of the environment should have highest priority (see 3.6.1 and 3.6.2). Comprehensive and detailed work programmes, including check-lists should be established comprising all operating manipulations required for safely shutting down and restarting the system. Critical path schedules can be useful tools in planning complex repair jobs. Evacuation of pipelines: Liquid products can be removed from pipelines using one or a combination of the following methods: - gravitation and/or suction from low points - replacement of line content by gas, air or water. The method to be selected depends on evaluation of a variety of technical, environmental, and economic factors, e.g. pipeline profile, accessibility, volume and properties of product, environmental conditions, logistics, availability and costs of gas, air and water supply. Some repair aspects: Pipe deformation and other damage (buckles, dents, cracks, corrosion holes) which materially affect the capability of the pipe to carry pressure, bending moment and/or tension should be repaired by replacement of the damaged section. If clamps are used as a (temporary) joint connection for such repairs, manufacturers' instructions for maximum allowable pressures and anchoring requirements should be followed carefully.
In offshore lines, new sections can be attached to the pipeline by hyperbaric welding or mechanical connectors. The use of hyperbaric welding is preferred for high pressure gas lines. In shallow water it is sometimes feasible to repair the pipeline by lifting both pipe ends (damaged section cutout on the seabed) above water. A new pipe section is welded in place and the line is laid sideways on the seabed (see also 2.2.2.2). Central Offices can assist with the selection of the repair method most suitable for local conditions, e.g. as part of the preparation of a pipeline repair manual.
4 . PIPELINE STANDARDS 4.1 General In the absence of statutory requirements it is common practice to design and operate pipelines in accordance with the ANSI Codes B31.4 and B31.8, for liquid and gas pipelines respectively, and with the documents that are referenced therein, These, together with several other relevant external standards, are listed below. Additional requirements to these external standards are being developed, where considered necessary by SIPM, to form 'Common Base' Group Standards. Stand-alone Group Standards are also being developed for use where no appropriate internationally recognised standards exist. Development of these Group standards is commencing in 1991. The list of proposed Group Standards is also given below. 4.2 External Standards The 'base' American codes for design, construction and operation of pipelines are: ANSI B31.4 Liquid transportation systems for hydrocarbons, LPG, anhydrous ammonia, and alcohols ANSI B31.8 Gas transmission and distribution piping systems ANSI B31.11 Slurry Pipelines Documents referenced in the above Codes: Other Codes ANSI B31G ANSI B31.3 ASME VIII
Manual for determining the remaining strength of corroded pipelines Chemical plant and petroleum refinery piping Boiler and pressure vessel code
Standards ANSI B16.34 ANSI B16.10 ANSI B16.11
Steel valves (flanged and buttwelding ends) Valve dimensions Forged steel fittings socket, welding and threaded
ANSI B16.25 ANSI B16.5 ANSI B16.9
API Std 1104
Butt weld ends Steel pipe flanges, flanged valves and fittings Factory made wrought steel buttwelding fittings
Welding of pipelines and related facilities
Recommended Practices API RP 5 L1 API RP 5 L2 API RP 5 L3 API RP 5 L5 API RP 5 L6 API RP 14 C API RP 1102 API RP 1107 API RP 1109 API RP 1110 API RP 1111
NACE RP-01-75 NACE RP-01-69
Recommended practice for railroad transportation of linepipe Recommended practice for internal coating of linepipe for noncorrosive gas transmission service Recommended practice for conducting drop-weight tear tests on linepipe Recommended practice for marine transportation of linepipe Recommended practice for inland waterway transportation of linepipe Details of protective devices on pipelines connected to platforms Recommended practice for liquid petroleum pipelines crossing railroads and highways Recommended pipeline maintenance welding practices Recommended practice for marking liquid petroleum pipeline facilities Recommended practice for pressure testing of liquid petroleum pipelines Recommended practice for design, construction, operation and maintenance of offshore hydrocarbon pipelines
NACE RP-02-74 NACE RP-06-75
Sulfide stress cracking resistant metallic materials for oilfield equipment Control of external corrosion on underground or submerged metallic piping systems High voltage electrical inspection of pipeline coatings prior to installation Control of corrosion on offshore steel pipelines
Publications API Pub 2200
Repairing Crude Oil, LPG, and Product Pipelines
API PSD 2201
Procedures for welding or hot tapping equipment containing flammables
Bulletins API Bul 5 C3 API Bul 5 T1
Calculations for pipe Nondestuctive testing terminology
Specifications API Spec 5 L API Spec 5 LU API Spec 6 D API Spec 15 HR API Spec 15 LR
Specifications for linepipe Specifications for ultra high test heat treated linepipe Pipeline valves Specification for high pressure fibreglass linepipe Specification for low pressure fibreglass linepipe
MSS-SP-44 MSS-SP-75
Steel pipe line flanges Specification for high test wrought buttwelding fittings
AWS 5.1-69 AWS 5.5-69 AWS AS.18-79 ASTM 662-87
Specificatiori for mild steel covered arc welding electrodes Specification for low-alloy steel covered arc-welding electrodes Specification for carbon steel filler metals for gas-shielded arc-welding Standard test method for holiday detection in pipeline coatings
Other external standards include: SIS O5 59 00
4.3
Pictorial surface preparation standards
Group Standards
The existing and proposed PETRONAS Technical Standard relating to pipelines, comprising mainly PTS, are listed below together with the appropriate external reference. Planned documents are designated PTS xx.xx.xx.xx.
PETRONAS Document
External Reference
General Company Documents
EP 86-0500 EP 64000 EP 55000
TMS Catalogue - Pipeline Engineering (code CB) E&P Project Management Guide E&P Maintenance Management Guide EP Safety Manual Engineering Computing Portfolio (ECP Pipeline Engineering)
-
General Manuals PTS 00.00.05.05 PTS 00.00.06.06 PTS 30.10.01.10 PTS 40.10.01.11
Specific Manuals PTS xx.xx.xx.xx
PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx
Index to PTS Publications Index to Standard Drawings Requisitioning Coding system for the administration and control of capital projects (Piping and Pipelines - groups 38 to 45)
Recommended Practices for Pipelines Transporting Hydrocarbons Guidelines on the design of pig traps Guidelines on the design of slug catchers Guidelines on the selection of pipeline valves Guidelines on the selection of pipeline coatings/field joints Guidelines on leak detection systems Guidelines on pipeline operations, maintenance and inspection Guidelines on pipeline repairs
-
ANSI B31.4/8
ANSI B31.4/8 API 1107
PETRONAS Document
PTS 30.10.73.10 PTS 31.38.01.15 PTS 31.38.60.10
Cathodic protection Piping classes-E and P Guidelines for hot tapping of pipelines, piping systems and equipment (updated with new title)
Technical Specifications PTS xx.xx.xx.xx design of c.p. systems for land pipelines PTS xx.xx.xx.xx design of c.p. systems for offshore pipelines PTS xx.xx.xx.xx design of pig trap systems for land pipelines PTS xx.xx.xx.xx design of pig trap systems for offshore pipelines PTS xx.xx.xx.xx design of GRP/GRE linepipe and fittings PTS 30.10.73.31 Cathodic protection of pipelines PTS xx.xx.xx.xx linepipe for non-critical service SS L-2-2/3 linepipe for critical non-sour pipelines SS L-3-2/3 linepipe for sour service pipelines PTS xx.xx.xx.xx duplex stainless steel linepipe PTS xx.xx.xx.xx clad linepipe PTS xx.xx.xx.xx NDT of linepipe (draft IS-1) PTS xx.xx.xx.xx GRP/GRE linepipe and fittings PTS xx.xx.xx.xx flexible pipe for flowlines and risers PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx
pipeline valve actuators carbon steel fittings for pipelines carbon steel fittings for sour service pipelines hot bends for carbon steel pipelines high grade pipeline flanges
External Reference
ANSI B31.3 API 2201
API 5 L API 5 L API 5 L API 15 HR -
MSS SP 75 MSS SP 75 MSS SP 75 MSS SP 44
PETRONAS Document PTS xx.xx.xx.xx pipeline isolating joints PTS xx.xx.xx.xx pipeline end closures PTS xx.xx.xx.xx duplex stainless steel fittings for pipelines SS L-4-1/2/3 PE coating of linepipe SS L-5-1/2/3 FBE coating of linepipe PTS xx.xx.xx.xx coatings for pipelines (various) PTS xx.xx.xx.xx concrete coating for submarine Pipelines
External Reference MSS SP 75 -
PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx
API 1104
PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx PTS xx.xx.xx.xx
Standard Drawings PTS 00.00.06.06
installation of GRP/GRE pipelines c.p. cable connection welding field welding of carbon steel pipelines field welding of duplex s.s. pipelines field welding of clad pipelines hyperbaric welding of carbon steel pipelines hyperbaric welding of duplex stainless steel pipelines coating of pipeline field joints hydrotesting, cleaning and drying of pipelines commissioning of pipeline c.p. systems
DIN 30670 -
API 1104 -
Index to standard drawings Standard Drawings are listed in PTS 00.00.06.06, with Group S 38 referring to Piping and Piping Components: S 38.010 Minimum length of welded branches on pipelines S xx.xxx Standard barred tee
PETRONAS Document Standard Requisitions PTS 30.10.01.10
External Reference
Requisitioning Standard Requisitions are listed in PTS 30.10.01.10, with the following requisitions relating to pipelines: Data Sheets PTS 31.38.01.93 Piping (sheets 1 and 2) Data/requisition Sheets None Requisition Sheets
PTS 31.36.90.93 PTS 31.38.81.93 PTS 31.38.81.94 PTS 31.38.82.93 PTS 31.38.82.94 PTS 31.38.82.95 PTS 31.38.82.96 PTS 31.38.82.97 PTS 31.38.84.93 PTS 31.38.85.95 PTS 31.38.85.95 PTS 31.38.89.93 PTS 31.38.89.93 PTS 39.40.20.93 PTS 40.10.01.93
Safety Relief Valves Pipe Linepipe for Transmission Systems Butt-welding Fittings Welding Branch Fittings Branch Outlet Nipples (welding ends) Branch Outlet Nipples (flanged) Branch Outlet Fittings Flanges Valves (standard) Valves (special) Stud Bolts and Nuts Stud Bolts and Nuts (heavy series) Metal/Polymer Flexible Pipe Engineering Documentation
PTS 40.00.10.93
Electronic Data Processing (EDP) Supplement
5 . SAFETY REQUIREMENTS FOR PIPELINES
5.1
General
Basic safety requirements for pipelines are included in all stages of a project, i.e. in design, construction, operation and maintenance procedures. Minimum design criteria regarding allowable pressures and other loads during installation and life of the pipeline are given by generally accepted pipeline design Codes, e.g. ANSI B31.4 for liquid pipelines and ANSI B31.8 for gas pipelines. The Institute of Petroleum Model Code of Safe Practice - Part 6 Petroleum Pipelines, contains more elaborate guidelines on safety-related matters. It is the task of the Inspection function to ensure that such design conditions are not violated during construction, commissioning and operation, and that the pipeline is not damaged by external factors. A selection of main aspects as given in the above references, supplemented or amended by SIPM experience is given below. The recommendations made are to be considered as minimum requirements; Operating Companies may impose more stringent requirements based on their experience and/or on statutory requirements in their area of operations. The recommendations given shall not be construed as replacing any Law, Rule or Regulation of a relevant Government Agency. The crucial aim of all safety measures is to ensure the safety of the public and personnel whilst maintaining reliable operations. Potentially undesirable events during pipeline operation are mainly over-pressure and leaks. Overpressure is primarily counteracted by pressure sensors at the upstream end of the pipeline with feed-back to the input source, e.g. pump station, which is normally provided with pressure or flow regulating devices, set to protect the pipeline against overpressure. Low pressure and backflow resulting from a leak can be detected by a pressure sensor and counteracted by a check valve located at the downstream end of a pipeline section. In emergency situations downstream facilities may have to be separated from the pipeline using an emergency shut-down valve. Alternatively over-pressure protection of such facilities may be provided by installing a surge relief system. Pipeline systems have to be provided with adequate protection against internal and external corrosion (see 1.3). This includes appropriate protective coatings and cathodic protection facilities for external protection. Protection against internal corrosion may require the use of inhibitors.
Pigging facilities should be accessible for instrumented tools to check the integrity of the pipeline (see 1.6). Pipeline systems containing toxic components, e.g. H2S, require special attention for safe operation (see HSE in Volume 1). 5.2
Onshore Pipelines
5.2.1 General Block Valves In order to limit the effects in case of major leaks, block valves are installed at intervals depending on diameter, pipe contents, type of environment and at major crossings, e.g. at waterways. Typical intervals between block valves in built-up areas (type B construction in Table 1.5-1) range from 10-20 km. The operation of block valves can be either manually or from the pipeline control centre. This depends mainly on pipe size, type of product and area population, and should therefore be considered for each specific case. The operational condition of the block valves should be checked at regular intervals. Patrolling A periodic pipeline patrol programme, usually by air, shall be maintained to observe surface conditions, leak indications, unknown third party construction activities, etc. Emergency Procedures In order to ensure that all operating staff and others likely to be involved, including the public services, are adequately informed regarding the action to be taken in the event of an emergency, specific procedures must be developed and formalised to meet the particular needs of every pipeline. The following aspects should be covered: -
liaison with public services and authorities description of pipeline system responsibilities of staff communication, alerting procedure information on contents of pipeline initial action and shut-down procedures emergency equipment remedial actions.
Such procedures should be rehearsed at regular intervals to ensure that all people concerned know their task and that procedures will be updated where necessary. Marking and Fencing The pipeline route should clearly be marked, especially at waterway crossings, road crossings and other places where third party interference may be expected. The telephone number of the pipeline control room should be prominently displayed on all warning signs. Block valve and measuring stations should be adequately fenced against unauthorised access; however, full protection against premeditated interference, e.g. sabotage, can generally not be obtained.
5.2.2 Liquid Pipelines Special attention should be paid to the possible occurrence of surge pressures resulting from inadvertent closing or opening of valves. Adequate controls and protective equipment shall be provided so that the level of pressure rise at any point will not exceed the internal design pressure by more than 10 percent. 5.2.3 Gas and Liquefied Gas Pipelines The design, construction and inspection requirements have to be matched to the environment, i.e. mainly the population density. Moreover, in many countries a certain distance should be maintained between pipelines and houses/ buildings which varies with pipeline diameter, working pressure, contents and effect-reducing facilities such as closely spaced block valves, etc. Limits on low temperatures resulting from rapid depressurisation, particularly of liquefied gases, should be considered in design, materials selection and operational procedures (see Volume 7, Part II). Special attention should be paid to above ground sections which may be exposed to fire. Protective measures may include liquid containment systems, sprinkler systems, fireproofing, etc. 5.3
Offshore Pipelines
Details of protective devices on pipelines connected to platforms are given in API RP 14C. These include pressure and flow sensors, check valves and pressure relief facilities.
It is recommended that long submarine pipeline routes be inspected regularly by air patrol. Moreover, regular underwater inspection should be carried out where there is risk of damage to the pipeline or where scour conditions may occur. Particular attention must be paid to design and location of pipeline risers, with respect to collision damage, inspectability, expansion, scour, surfzone protection, etc. The installation of a subsea emergency shut-down valve or check valve in longer gas and condensate pipelines might be considered as a measure to provide additional protection for platforms.
6 . DOCUMENTATION 6.1
General
Documentation is produced at all stages during the life of a pipeline, from design to abandonment. All essential documentation should be retained, be accessible and regularly updated, as required, throughout the life of a pipeline 6.2
Engineering Stage
Handover from Engineering to Operations asset holder at the commissioning stage is a particularly important step. This should be formalised and include the handover of documents which effectively 'certify' the pipeline. This 'certification' documentation should be initiated at the project definition stage and include a pipeline design and operating philosophy setting out the purpose of the new system and its main design, construction, operational and maintenance features. It will also include as-built records and a construction report as detailed below.
6.2.1 As-Built Records Upon completion of pipeline construction activities an as-built record of the pipeline should be made. The as-built record provides an official record of the installed pipeline and includes such information as: -
precise routing of the pipeline pipeline size, grade, wall thickness, coating, etc. facilities installed on the pipeline, i.e. block valves, cathodic protection points, markers, etc. facilities crossed by the pipeline, e.g., other pipelines, rivers, roads and railways (onshore only), etc. - depth of cover over pipeline other relevant features, i.e. location of span lengths, buckle arrestors, anodes in offshore pipelines. The as-built records are essential information required by the pipeline operator for future inspection and maintenance of the pipeline.
In many cases extracts from the as-built records, e.g. pipeline routing, are incorporated into legal documentation defining the extent of the permanent pipeline easement, or into operating licences which permit the pipeline owner to utilise the pipeline. In addition to the foregoing it is strongly recommended, and in some cases mandatory subject to local legislative requirements, for the inspection records compiled during the construction phase, and in particular the pipe and weld numbers/locations and the weld X-ray or radiographs, to be retained by the pipeline operating company for a minimum specified number of years after putting the pipeline into service. This information can be invaluable when investigating a failure in the pipeline during its operational lifetime and if not identifying the likely cause can at least eliminate some of the possibilities.
6.2.2 Construction Report The objective of the construction report is to briefly review the execution of the construction phase with particular reference to problems/difficulties encountered and which could be avoided or planned for in any future similar project. Photographs, which can be a very useful supplement to the report, should be made use of wherever possible. The report should also contain a brief summary of contractors' performance In order to avoid key information being lost it is suggested that a single summary document 'Critical Operating Parameters' be used as the prime handover document to Operations. This should cover, in addition to any specific licence requirements: - the Code with which the installation is meant to comply - the design basis i.e. operating limits, design life, any special features, etc - the main operating, maintenance and inspection requirements. 6.3
Operations
The 'Critical Operating Parameters' should be the base against which future hardware or procedural changes are made i.e. the basis of an operations change control procedure. In order to be effective in safeguarding the technical integrity of the pipeline the change control procedure must be applied continually throughout the operations phase through to abandonment. Implicit in this procedure is the regular updating of the base documentation.
7 . REFERENCES AND FURTHER READING
DESIGN (1)
Hydraulics (1.1) References
1. Gas Processors Suppliers Association (GPSA) SI Engineering Data Book, 1980 2. Perry, R. H. and Chilton, C. H., Chemical Engineers' Handbook, 5thEd., McGraw Hill, 1983 3. Baker et al., Design Manual for Two-Phase Flow. American Gas Association 4. Eaton et al., The prediction of flow patterns, liquid hold-up and pressure losses occurring during continuous two-phase flow in horizontal pipelines. October 1966, American Instit. Mining, Metallurgical and Petroleum Engineering
Further Reading - Waxy Crudes in Relation to Pipeline Operations. Several articles in J. Inst. Pet. Vol.57,1971
Pipe Stability (1.4) Further Reading -
Hassan, U., Jewsbury, C. E. and Yates, A. P. J., Pipe Protection. Published by: BHRA Fluid Engineering, Cranfield, Bedford MK 43 OAJ, U.K., 1978
Stresses and Loads (1.5) Further Reading - Marks: Standard Handbook for Mechanical Engineers; 8th Ed. by Theodore Baumeister et al., McGraw-Hill Book Company, New York - Mousselli, A. H., Offshore Pipeline Design, Analysis and Methods. Penn-Well Books, PennWeII Publishing Company, Tulsa, Oklahoma - Pierce, R. N. et al., Design Considerations for Uncased Road Crossings. Pipeline Industry, May 1978 - Roark, R. J. and Young, W. C., Formulas for Stress and Strain. 5th Ed., McGraw-Hill Book Company, New York Timoshenko, S., Theory of Elastic Stability. McGraw-Hill Book Company, New York, 1936 - Design of Piping Systems. M. W. Kellog Company, 2nd Ed., 1967 (Edited by John Wiley and Sons, New York) - Den Hartog, J. P., Advanced Strength of Materials. McGraw-Hill Book Company, New York, 1952
CONSTRUCTION (2)
Landline Construction (2.1) Further Reading - Standard for Welding Pipelines and Related Facilities. API Std 1104, Sixteenth Edition, 1983 - Liquid Petroleum Transportation Piping Systems. ANSI/ASME B 31.4 - Gas Transmission and Distribution Piping Systems. ANSI/ASME B 31.8 - Chemical Plant and Petroleum Refining Piping. ANSI/ASME B 31.3 - Recommended Practice for Railroad Transportation of Line Pipe. API RP 5L1, Third Edition, April 1972 - Recommended Practice for Marine Transportation of Line Pipe. API RP 5L5, First Edition, March 1975
- Recommended Practice for Liquid Petroleum Pipelines Crossing Railroads and Highways. API RP 1102, Fifth Edition, 1981
Cleaning/Drying/Pigging (2.5) References 1. T. D. Williamson, Inc., Guide to Pigging. August 1979
Further Reading - Pipeline pigging - An art? a science?. PEB (Pipeline Equipment Benelux), Sept 1983 - Comparative description of the various methods used to dry pipelines. Petrole Informations, Sept 1979
OPERATIONS (3)
Routine and Special Operations (3.5) Further Reading - Krass, W., Kittel, A. and Uhde, A., Pipeline Technik: mineraloel fernleitungen. Verlag Tuer Rheinland, GmbH, Ko&& ln , 1979
Pipeline Repair (3.6) Further Reading - Kietner, J. F., Repair of Line Pipe Defects by Full Encirclement Sleeves. Batelle Columbus Laboratories, 1977 - Kiefner, J. F., Welding Criteria Permit Safe and Effective Pipeline Repair. Pipeline Industry, Jan.1980 - Pickell, M. B., Pipeline Plugging Methods Keep Pace with Industry Needs. Oil and Gas Journal, March 3, 1980
Note: Comments by letter or telex should include all the above information and be sent to the PETRONAS custodian department concerned (see title page).
