Induction Bending is a precisely controlled and efficient piping bending technique. Local heating using high-frequency induced electrical power is applied during the induction bending process. Pipes, tubes, and even structural shapes (channels, W & H sections) can be bent efficiently in an induction bending machine. Induction bending is also known as hot bending, incremental bending, or high-frequency bending. For bigger pipe diameters, when cold bending methods are limited, Induction bending of pipe is the most preferable option. Around the pipe to be bent, an induction coil is placed that heats the pipe circumference in the range of 850 – 1100 degrees Celsius.
Induction Bending (Hot Bending) Process
The following steps are performed for the induction bending of the pipe or pipeline system:
The pre-inspected pipe or pipeline to be bent is placed in the machine bed and clamped hydraulically.
Around the pipe, induction heating coils and cooling coils are mounted. To ensure uniform heating, the induction coil can be adjusted with a 3-plane movement.
By adjusting the radius arm and front clamp, the required bend radius can be fixed. There is one pointer to display the correct degree of turning.
Arc lengths are marked on the pipe. The pipe can be moved slowly whilst the bending force is applied by a fixed radius arm arrangement.
Once everything is set as required, hydraulic pressure, water level, and switches are inspected and then the induction bending operation is started.
Upon reaching the required temperature range, the pipe is pushed forward slowly at a speed of 10-40 mm/min, and the operation is stopped when the specified bend angle and pre-determined arc length are reached.
Just beyond the induction coil, the heated pipe material is quenched using a water spray on the outside surface of the pipe.
In the next step, the induction bend is removed and sent for inspection and measurement of tolerances.
The final step for the induction bends is the use of post-bend heat treatments for stress relieving, normalizing, etc.
Fig. 1 below shows a typical induction bending process.
Fig. 1: Typical Induction Bending Process
Induction bends are normally produced in standard bend angles (e.g. 45°, 90°, etc.). However, depending on the requirement they can be custom-made to specific bend angles. Compound out-of-plane bends in a single joint of pipe can also be produced. The bend radius for induction bending is specified as a function of the nominal pipe diameter (D) like 5D, 30D, 60D bends, etc. Fig. 2 below provides a schematic diagram of the induction bending mechanism.
Fig. 2: Schematic Diagram of Induction Bending Mechanism
The important parameters that affect the induction bending process are:
Pipe Diameter
Surface Contamination
Process Parameters like Temperature, Speed, Cooling rate, etc
Bend Radius
Bend Angle
Process Interruptions
Hardenability of the Pipe Material, etc.
Induction Bending Standards
As the complex induction bending process involves various steps for producing bends, it must be controlled precisely to produce quality items. Different codes and standards govern this process. The most conventional and widely used standards for induction bends are the
ASME B16.49
ISO 15590-1(en)
Shell DEP 31.40.20.33
Advantages of Induction bending
The major advantages of induction bending are:
Lower risk of wall thinning and deformation of the cross-section
Thin-walled pipes can easily be bent.
Less costly and available faster than traditional components.
Uniform hardness and thickness.
Smooth flow due to large radii reducing friction, wear, and pump energy.
No pipe wrinkles.
Only a straight pipe is required for induction bending.
Precise bending radius and angle.
Diverse bendings: square pipe, flat bar, I-beam, H-beam, channel section, etc.
Applications of Induction bends
The majority of the Induction bends are found in the pipeline systems for liquid and gas transportation. Additionally, they are found in applications requiring large diameter bends with precision and reliability and where the laminar smooth flow is required. Typical applications of induction bends include the following industries:
Onshore and Offshore pipelines in the oil & gas sector
The refinery, chemical, and petrochemical sector
Powerplants
Industrial equipment
Infrastructure constructions and steel building constructions (a.o. bridges, construction, art objects, roller coasters)
Offshore energy (a.o. J-tubes, S-jubes)
Metallurgical industries
Shipbuilding, etc.
Induction Bending Materials
The following pipe materials are normally used for forming by induction bending:
Its commonly called “Water Hammer”, and is defined as a sudden increase in pressure due to an instantaneous conversion of momentum to pressure when flowing liquid stops quickly.
Hydraulic surge is often caused by the transformation of kinetic energy to potential energy as a stream of fluid is suddenly stopped.
Once the pump tripped, you will observe that the pressure in the immediate discharge is decreasing because the flow still going forward with no current supply and a strong wave will rush back towards the pump discharge coming all the way from the close endpoint creating the pressure spike.
As noticed in the below graph, pressure spikes will continue hitting the pipe/pipeline trying to release the generated excessive energy and therefore your system will be at risk.
ASME B31.3defined that the pressure rise due to surge and other normal operation variations shall not exceed the internal design pressure at any point in the piping system and equipment by more than 33%.
Here you have to ask yourself, Do I Have a Safe & Reliable System to Operate?!!!
All of the above will generate pressure waves that travel both upstream and downstream from point of origin.
Please note that some pipelines are in transient operations over 75% of the time.
Surge (pressure rise) increases as much as the pipeline segment length increases since the contained momentum will be higher (more volume).
A pressure surge can consist of multiple events, resulting in up to ten times the normal pipeline pressure. When a surge relief valve opens, it vents the pressure to a safety system. Also, it is worth mentioning that Surge pressure is created during the last 20% of valve closure.
The rapid closure of a valve can result in an initial reduced pressure downstream which may be sufficient to reduce the absolute pressure below the vapor pressure and generates a cavitation scenario.
The cavitation might lead to higher transient pressures and unbalanced forces.
Also, Fast pressurization of a closed system, can double the pressure rise at the far end of the system as the pressure wave is reflected from the closed end.
This can arise either from the fast opening of a valve at the system inlet or due to pump startup with the pump discharge valve open.
The surge may result in the creation of huge unbalanced forces within the piping system which may damage the supports, collapse pipe bridges, or even line rupture and displacement from its original location.
Experiences indicate that the failure of pipework supports as a result of pressure surge is more likely than pipeline rupture due to overpressure.
Challenges of Water Hammer
Surge can significantly exceed the Maximum Allowable Operating Pressure (MAOP) plus any additional overpressure allowance, typically 33% above MAOP.
The sudden transition from momentum force (flow) to pressure force will lead to shaking/vibration of pipeline/piping and might lead to severe damage in pipeline/piping if the system design is not adequate.
Your system could be equipped with a surge relief valve, however, missing calibration and regular checks could lead to failure of the valve to act as required and accordingly lead to destructive failure of the system.
Serious Industrial Incidents due to Lack of Proper Surge Protection
In 1999, a pressure relief valve failed on a 16-inch gasoline pipeline operated by the Olympic Pipe Line Company in Bellingham, Wash., spilling 277,000 gallons of gasoline into the river. The gasoline exploded, killing three young boys. The incident resulted in five felony convictions for Olympic employees and a $75 million wrongful death settlement.
In 2009, at the Sayano-Shushenskaya hydroelectric plant in Siberia, a severe water hammer ruptured a piping segment going to a turbine due to improper surge relief system design. A transformer exploded, killing 69 people.
Calculation of Water Hammer
A- Manual calculation – Joukowski formula:
Role of Thumb used in the past to estimate the surge pressure, considering that the only variable is the velocity, P is equal to
0.8 * Weight of liquid per cubic foot * Velocity Change
Another old way to estimate is to consider a 50 Psi change in pressure with the velocity change of every 10 ft/sec
Can you still use these formulas?
Yes BUT ONLY while you are standing for a quick and rough estimation.
The Joukowsky equation is a simplified method for calculating the peak transient pressure experienced when a valve is closed against a fluid in motion and may be represented as follows:
ΔP=ρ a Δv
ρ Liquid Density
a Pressure Wave Velocity
Δv Change in Liquid Velocity
The Joukowsky equation takes into consideration the elasticity of the pipe wall and the compressibility of the fluid itself through the calculation of the speed of sound (a), however, assumes instant closure of the valve.
Pipe Properties: Roughness, Young Modulus & Poisson ratio.
Explanation of main inputs:
Bulk modulus: is the property characterizing the compressibility of a fluid, i.e. how easily a unit volume of a fluid can be changed when changing the pressure working upon it.
The Bulk Modulus Elasticity can be expressed as:
Some fluids have ready-calculated Bulk Modulus Elasticity:
Relative roughness: Is the ratio between absolute roughness and pipe diameter Relative roughness can be expressed as:
Some pipe material Roughness is available :
Young Modulus: is a measure of the stiffness of an elastic material. It is used to describe the elastic properties of pipeline/piping.
Some pipe material’s Young Modulus are available :
Poisson ratio: the ratio of the relative contraction strain (transverse, lateral or radial strain) normal to the applied load – to the relative extension strain (or axial strain) in the direction of the applied load
Although the Joukowsky formula is far better and more precious than the past rough estimation formulas, still it can be only applicable to a limited subset of fluid systems.
Its application should be limited to situations matching the following criteria: Simple ‘linear’ piping systems i.e. there are no branches by which pressure waves can be reflected back and cause constructive interference in the mainline. Valve closure time is significantly shorter than the pressure wave communication time. System frictional losses are similar to that of a water transport system.
Additionally, the Joukowsky equation does not consider column separation in its analysis of fluid hammer. Column separation can often result in surge pressures exceeding those predicted by the Joukowsky equation and therefore the Joukowsky equation should not be applied when analyzing a system in which the pipeline pressure can rapidly drop below the fluid vapor pressure.
As a process engineer, you can use it to verify vendor documents or to identify the healthiness of your system, however, for accurate and precise data you need to run PIPENET or similar software to estimate accurately the pressure rise. Then you will be translating this data into generated forces.
Once you have the generated forces, pick up the phone and call the piping engineer to run CAESAR software which will verify whether the piping/pipeline is granted well-designed supports and structure to make sure that it will not go anywhere else after the surge event occurs.
B- Pressure Transient Assessment using Modelling Software
There are currently various software packages that can be used for analysis such as
HyTran
Flowmaster
WANDA
Hammer
AFT Impulse
PIPENET
PTRAN
Sample of Pressure Transient Assessment using PIPENET
LNG Bunkering System Pressure Transient using PIPENET
Surge Protection Systems
Initially, we need to agree on the fact that the surge phenomenon is inevitable and therefore we have to identify an optimized option to protect our system with the least associated cost (CAPEX / OPEX). Please refer to our previous article on Optimization @ https://whatispiping.com/process-optimization
Design Consideration of Surge Protection systems:
The design of a complete surge relief system is dependent upon a complex range of factors, including the potential for pressure increases, the volumes which must be passed by the surge relief equipment in operation, and the capacity of the system to contain pressures.
Control or ESD valve closure times can also affect surge pressures in a pipeline. By extending valve closure time, a more gradual flow decay can be achieved.
Control narrative and system interlocks to ensure Staged pump shutdown sequence and linked ship/shore ESDs when your facility is linked to loading berths/jetties.
Carry out transient/surge analysis using detailed computer modeling to simulate the complex interactions of equipment, pipelines, and fluid to normal, fault, and emergency events.
Design piping to withstand maximum surge pressure – MSP.
Although many design approaches can help reduce surge pressures in pipelines, going for a higher pipe rating or massive support arrangements aren’t recommended for an associated significant cost, and a surge relief valve is found to be the most feasible option to protect the system.
A correctly designed surge relief system will include components to dampen or slow the relief valve on closing, and this often requires sophisticated reverse flow plots.
In nitrogen-loaded Surge Relief valves, attention must be paid to the nitrogen gas system. The nitrogen system must supply a constant pressure (setpoint) to the modulating valve, even under conditions of varying ambient temperatures. Normally, the system is designed to use standard gas bottles and has its own control system to regulate the nitrogen supply pressure.
Surge Relief Solutions / Devices:
Ensure Proper design is applied considering the worst-case scenario with its respective control narrative for valve interlocking and proper mitigating means are in place.
MOVs / ESD Closing time are enough to absorb the wave velocity created by Surge. This can be assured by having a proper Equipment strategy in place which will ensure that Surge relief valves’ set points are verified and the valves are being calibrated on regular basis to ensure that they will be operated whenever required.
Ensure that operating procedures are in place and operations are well-trained and competent to operate.
Line design pressure/rating.
Piping Supports are well designed to withstand the shaking/vibration resulting from Surges.
Surge relief valve and associated relief Drum.
In general, Protection systems can be classified as either Active or Passive:
A- Active Protection
By using devices to actively protect the systems against the effects of pressure surge during pipeline normal operation like:
Please note that if there is a shortfall or limitation of this document then it is because of me, while any success or correctness would be solely from the great and generous Allah.
Resources
ASME B31.4 Pressure Pipeline Code prescribes requirements for the design, materials, construction, assembly, inspection, and testing of piping transporting liquids such as crude oil, condensate, natural gasoline, natural gas liquids, liquefied petroleum gas, liquid alcohol, liquid anhydrous ammonia, and liquid petroleum products between producers’ lease facilities, tank farms, natural-gas processing plants, refineries, stations, ammonia plants, terminals, and other delivery and receiving points.
API RP 520, ‘Sizing, Selection, and Installation of Pressure-Relieving Devices in Refineries, Part 1 – Sizing and Selection’, Seventh Edition, January 2000.
API RP 521, ‘Guide for Pressure-Relieving and Depressurizing Systems’ Fourth Edition, March 1997.
CRR 136/1998, Workbook for Chemical Reactor Relief Sizing, HSE.
DIERs Manual ” A perspective on Emergency relief system” by DIER Technical Committee. Guide to Pressure Relief (PSG 8), Part C: Section 5, 1999.
Chemical Engineer’s Handbook – Perry, Seventh Edition
“Investigation Report: Refinery Explosion and Fire,” U.S. Chemical Safety and Hazard Investigation Board, March 2007.
“Olympic Pipe Line accident in Bellingham kills three youths on June 10, 1999,” History.org.
“Lessons from Russian Hydroelectric Plant Accident,” Engineering Ethics Blog.
“An Introduction to Liquid Pipeline Surge Relief,” Emerson Process Management, April 2007, page 2.
Want to know more!!! Kindly refer to the following:
As per CAPP – Canadian Association of Petroleum Producers, a flare system is defined as the controlled burning of natural gas that cannot be processed for sale or use because of technical or economic reasons. On the Other hand, API 537 defines a flare system as the system provided in a refinery or petrochemical plant to ensure the safe and efficient disposal of relieved gases or liquids.
The efficient flaring system exists at any facility accommodating Hydrocarbon pressurized systems such as:
Refineries.
Natural gas processing plants.
Petrochemical plants.
Wells / Rigs.
landfills.
Application of Flare System
Flares are primarily used for burning off flammable gas released by pressure relief valves during any over-pressure scenario of plant process unit/equipment, due to process upset or during startups & shutdowns, and for the planned combustion of gases over relatively short periods.
Flare systems are used for a variety of activities such as:
Fig. 1 shows a typical flare system in a process plant. The important features of a flare system are
When any equipment in the plant is over-pressured, the pressure relief valve is an essential safety device that automatically releases gases and sometimes liquids.
The height of the flame depends on the volume of released gas, while brightness and color depend upon composition.
The released gases and liquids are routed through large piping systems called flare headers to the flare. The released gases are burned as they exit the flare stacks.
Commonly, flares are equipped with a vapor-liquid separator (also known as a knockout drum – KOD) upstream of the flare to remove any large amounts of liquid that may accompany the relieved gases to avoid fireballs.
Steam is very often injected into the flame to reduce the formation of black smoke.
When too much steam is added, a condition known as “over-steaming” can occur resulting in reduced combustion efficiency and higher emissions.
To keep the flare system functional, a small amount of gas is continuously burned, like a pilot light, to assure that the flare system is always ready for its primary purpose as an over-pressure safety system.
Fig 1: Typical Flare System
When does a Flaring Incident Take Place?
The flaring system is normally activated during the following situations
There is in fact no standard composition and it is, therefore, necessary to define some group of gas flaring according to the actual parameters of the gas.
For NGL & LNG plants, the flared gas composition is expected to be 80 – 90 % C1 & balance is C2+ & Inert gases such as N2 and CO2.
Gas flaring from refineries and Petrochemical plants will commonly contain a mixture of paraffinic & Olefinic HC, inert gases, and H2.
In landfill gas & biogas plants, the flared gas composition is a mixture of CH4 and CO2 along with small amounts of other inert gases.
Note: Changing gas composition will affect the heat transfer capabilities of the gas and affect the performance of the measurement by a flowmeter.
Flare system components
Fig. 2 below shows a typical flare system with elevated flare. The important flare system components are marked in the image.
Fig. 2: Typical Flare System with Elevated Flare
Types of Flares
Vertical
Self Supported.
Guyed (Cables).
Derrick supported (Steel).
Horizontal
The flared fluids are piped to a horizontal flare burner that discharges into a pit or excavation.
Enclosed Flame Flares
They are designed to conceal flares from direct view, reduce noise, and minimize radiation.
All the above flare types can be either single-point or Multi-burner staged flares. Also, Flares can be classified as either
smokeless (using air, steam, pressure energy, or any other means to create turbulence and entrain air within the flared gas stream ) or
Non-smokeless flares (used when smoke isn’t a concern or the flared fluid doesn’t generate smoke such as H2, NH3, H2S…etc).
Flare System Selection Considerations
The Flare system is normally selected based on the following considerations.
Safety requirements and environmental regulations must be satisfied.
CAPEX & OPEX.
Gas process conditions and properties.
Neighborhood relationships, availability, and cost of utilities.
Space availability.
Flaring Environmental impacts
The global warming potential of Methane is estimated at 34 times greater than that of CO2. Therefore, by converting the methane to CO2 before it is released into the atmosphere, the amount of global warming is reduced. However, flaring emissions contributed to 270 Mt CO2 in 2017, and reducing flaring emissions is key to avoiding dangerous global warming.
Improperly operated flares may emit methane and other volatile organic compounds as well as sulfur dioxide and other sulfur compounds, which are known to cause respiratory problems.
Emissions from improperly operated flares like aromatic hydrocarbons (benzene, toluene, xylenes) and benzo(a)pyrene, etc. are known to be carcinogenic.
It is now recognized as a major environmental problem, contributing an amount of about 150 billion m3 of natural gas that is flared around the world, contaminating the environment with about 400 Mt CO2 per year.
Gas Flaring Reducing and Recovery (R&R)
There are many types of FGRS (Flare Gas Recovery Systems) in the industry:
Collection, compression, and injection/reinjection
Generating electricity by generation and co-generation of steam and electricity
The gas collection and compression into pipelines for processing and sale is a well-established and proven approach to mitigating flaring and venting. According to environmental and economic considerations, FGRS has increased to reduce noise and thermal radiation, operating and maintenance costs, air pollution, and gas emission, and reduces fuel gas and steam consumption. Fig. 3 below shows a typical example of a flare gas recovery system.
Fig. 3: Typical Flare Gas Recovery System
Flare System Design
API 537 is used for flare system design. This standard is applicable to Flares used in pressure-relieving and vapor-depressurizing systems used in General Refinery and Petrochemical Services. Although this standard is primarily intended for new flares and facilities, it may be used as a guideline in the evaluation of existing facilities together with appropriate cost and risk assessment considerations. API 537 must be referred to in consideration with
API RP521 (Guide for Pressure-Relieving and Depressurizing systems), and
API 560RP2A (Fired Heaters for General Refinery Service Recommended Practice and constructing fixed offshore platforms).
Factors Affecting Flare System Design:
Design factors that influence the flare system design are:
flow rate;
flare gas composition;
flare gas temperature;
gas pressure available;
utility costs and availability;
safety requirements;
environmental requirements;
social requirements.
The plant owner or the plant designer must provide these factors to define the flaring requirements.
A. Flare System Design Criteria
The prime objective of a flare system design is safe, effective disposal of gases without compromising appropriate design considerations like:
Reliable effective burning to reduce emissions to the permitted level.
System hydraulics shall be sufficient to deliver all of the waste gas and auxiliary fuel gas, steam, and air to the flare burner with sufficient exit velocities. System pressure cannot exceed the maximum allowable operating pressures at any active relief source, vent, or utility supply.
Liquid shall be removed sufficiently to prevent poor combustion, burning liquid droplets, and clogging the flare burner.
Air infiltration should be avoided using a proper seal system to avoid internal combustion within the riser and flashback in the flare header.
Flame radiation should be controlled within admitted limits to avoid nearby property damage or personnel injury.
A smoke suppression system, if required, should ensure Zero smoke operation.
Flare gas recovery system feasibility to be assessed to enhance plant efficiency and eliminate flaring incidents.
B. Flare Header Sizing
The take-off point for flare header sizing is to have a proper relief load calculation based on the worst credible scenario, where the pressure will increase until a predetermined relief pressure is reached, at which point the relief pressure valve will open, decreasing the pressure after the turnaround time. Refer to Fig. 4.
Fig. 4: Flare Header Sizing Criteria
ASME Boiler & Pressure Vessel Code VIII Guideline For overpressure protection Requirements:
The ASME Boiler and Pressure Vessel Code Sec VIII sets out requirements for standard pressure vessels (left) and the relief valves (right) protecting them as a percentage of the maximum allowable working pressure (MAWP) as shown in Fig. 5.
Fig. 5: ASME Sec VIII Criteria for Flare Sizing
Relief Valve Sizing Procedure
Refer to Fig. 6 below which shows a typical flowchart explaining the steps for the relief valve sizing procedure.
Fig. 6: Relief Valve Sizing Procedure
Fig. 7 below shows a typical flare header system for a processing plant.
Fig. 7: Typical Flare Header System
Low-pressure pipe flares are not intended to handle liquids. Also, they do not efficiently perform when there is a liquid hydrocarbon release into the flare system.
Backpressure and Gas Velocity are the major criteria governing the sizing of the flare header.
The flare header size has to be large enough to prevent excessive back pressure on the plant safety valves and to limit gas velocity and noise to acceptable levels.
Fig. 8: Flare Headers and Sub-headers
Steps for finding ‘the maximum’ relief load for a specific process plant:
Prepare flare relief load summary including all Pressure Safety Valve with all of their relief cases.
Find out the maximum possible relief load for each of the cases, e.g. For cooling water failure, all Pressure Safety Valves (PSV) having this case will discharge simultaneously. So add up them. Note: The simultaneous occurrence of two or more contingencies (known as double jeopardy) is so unlikely that this situation is not usually considered as a basis for determining the maximum system loads.
Once you found the maximum case among all the scenarios, consider it as the ‘governing’ case for sizing your flare header.
You need to find what has superimposed back pressure at the plant battery limit. You need to calculate total back pressure based on superimposed backpressure and built-up backpressure. All these calculations need a thorough understanding of hydraulics and API guidelines.
Once you perform the above, you will have the size of a flare header
The sum of all pressure losses starting from the flare stack up to the safety valve yields the total backpressure. This backpressure must be lower than the maximum backpressure allowed in the system & corresponding to the lowest set pressure of the safety valves.
Hydraulic Design
The flare header is sized to limit the backpressure of each pressure relief device during various emergency events. The hydraulic design is a line sizing/rating problem:
Design minimizes the differential pressure to ensure each pressure relief device functions
Design is based on specific line length, size and the maximum expected relief load for each relief event.
Hydraulic Issues
Hydraulic issues specific to the flare header design:
The size of various sections is governed by the different relief events in the collection header.
A variety of material discharge to the flare system.
Potential pressure discontinuities where pipe flow stream meet.
Volume expansion throughout header piping.
High velocity and significant acceleration effects.
C. Flare Knock-Out Drum Sizing
The objectives of a knock-out drum are
Limit liquid droplet size entrained with gas to the flare to avoid liquid carryover to flare tip, smoke, flaming rain, and other hazardous conditions.
Provide adequate residence time for liquid.
Fig. 9 shows a typical known out drum (KOD). KOD is sized based on API 521.
Separation of liquid droplet size of 300-600 microns considering the design case for the flare.
20-30 minutes of liquid hold-up time based on a relief case that results in maximum liquid.
No internals to facilitate separation.
Many orientations/options possible, horizontal KODs most preferred.
Fig. 9: Typical Flare Knock-Out Drum
Flare Knock-Out Drum Elevation
KO drum elevation decides pipe rack elevation based on the 1:500 slope of the main flare header
KO drum elevation determined by pump NPSH requirement
Liquid Hold up requirement during a major liquid or two-phase release.
A sufficient distance shall be available between the inlet & HHHLL. It is possible to have manually initiated depressurization even after HHHLLL. Any possible liquid shall be accommodated above HHHLL.
Knockout drum sizing is basically a trial-and-error process.
Distance between HLL and HHHLL shall be designed to accommodate the maximum liquid release scenario.
Determination of the drum size for liquid entrainment separation is The first step.
HHHLL is usually taken as the distance from the maximum liquid level.
The vertical velocity of the Vapour and gas should be low enough to prevent large slugs of liquid from entering the flare.
The thermal radiation fluxes and smoking potential are increased by the presence of small liquid droplets.
When do the Liquid particles separate?
Sufficient residence time.
When the gas velocity is sufficiently low to permit the liquid dropout to fall.
Long-term field experience has shown that the dropout velocity in the drum may be based on the necessity to separate droplets from 300 μm to 600 μm in diameter.
D. Flare Stack Sizing
Flare Load, Radiation, and stack height: Flare stack height depends on the flame radiation intensity, therefore you will need first to estimate the generated radiation in order to be able to identify the minimum acceptable stack height. Thermal radiation can be calculated by the following equation (Fig. 11):
Fig. 11: Thermal Radiation from Flare Stack
Flame length is a determining factor for the intensity of radiation and its angle in relation to the stack. It can be calculated using the following equation (Fig. 12):
Fig. 12: Equation for Flame Length and Angle calculation
Using Flame length and flame angle, Radiation intensity can be determined and accordingly flare stack from charts.
E. Liquid Seal Drum
Liquid Seal Drum prevents the flashback from flare tip back to flare headers. It also helps to avoid air ingress into the flare system when the flare system is integrated with a flare recovery system or due to hot gas thermal contraction and/or condensation which can result in a substantial vacuum in the flare header. Fig. 13 shows a typical liquid seal drum.
Fig. 13: Typical Liquid Seal Drum
Note that the maximum vacuum protection achievable may be limited by piping and vessel elevations, In addition to maintaining the proper liquid level and restoring the level promptly after any hot relief and before the vacuum forms.
For extremely cold releases, the water as a liquid sealing fluid is not recommended. In such cases, water-glycol mixtures of sufficient concentration shall be used.
F. Flared Gas Measurement
As we get familiar with the impact of improper flaring on health and the environment, also it is highly required to measure the HC quantities sent to flare to decide on the plant performance, identify gaps and define the mitigating actions to eliminate or at least reduce flaring.
When trying to measure gas flaring, There are many challenges, including diameters of large pipes, high flow velocities over wide measuring ranges, gas composition changing, low pressure, dirt, wax, and condensate.
Important criteria to be considered to decide on the flow measurement instruments:
Operating range, the meter should accommodate the anticipated range of flows.
Accuracy will depend on the final use of the measurement data and applicable regulatory requirements.
Installation requirements, the flow meter should be installed to be able to measure the total final gas flow to the flare and be located downstream of any liquids knock-out drum.
Maintenance and calibration requirements.
Composition monitoring as most types of flow meters is composition dependent. There are two primary options for composition monitoring:
Sampling and subsequent laboratory analysis.
Online Analyzers.
Temperature and pressure corrections, the flow meter will need temperature and pressure compensation features to correct the measured flow to standard conditions (101.325 kPa and 15°C) or normal conditions (101.325 kPa and 0°C).
Multi-phase capabilities, if the gas stream contains high concentrations of condensable hydrocarbons, the gas flow meter should be installed as close as possible to the knockout drum, and consideration should be given to insulating and heat tracing the line.
Stainless Steel may be used for offshore platform’s corrosive saltwater on all exposed instrument materials, including sensors, process connections, and enclosures. Agency approvals for installation in hazardous locations, in environments with potential hazardous gases; enclosure-only ratings are inadequate (and risky).
Monitoring records should be kept for at least 5 years. These records should be included the flow measurement data, hours the monitor during operation, and all servicing and calibration records.
In flow verification, where a verifiable flaring rate is desired (provers), the systems should be designed or modified to accommodate secondary flow measurements to allow an independent check of the primary flow meter while in active service.
Flow test methods may be considered for making spot checks or determinations of flows in the flare header.
Stainless steel wetted parts and optional stainless steel process connections and enclosure housings.
Non-clogging, non-fouling, no moving parts design for lowest maintenance.
Must be in compliance with local environmental regulations. It should meet mandated performance and calibration procedures such as US EPA’s 10 CFR 40; 40 CFR 98; EU Directive 2007/589/EC; US MMR 30 CFR Part 250 and others
The main types of flow meter technologies for flare gas measurement in the industry are listed in Fig. 14 below:
Fig. 14: Typical Flowmeters for Flare gas measurement
A Cladded Pipe is a steel pipe having a metallurgically bonded Corrosion-Resistant Alloy (CRA) layer on its internal or external surface. The base material is carbon steel or low alloy steel. Clad pipes comply with the most stringent requirements of strength and corrosion resistance. The carbon steel outer pipe (backing steel or base metal) complies with the static requirements of strength and durability, whereas the highly alloyed inside pipe provides protection against corrosion. As more and more pipelines are operated under highly corrosive conditions, the use of CRA-cladded pipe is increasing in the pipeline industry, especially in offshore areas.
Applications of Cladded Pipe
An internal layer of corrosion-resistant alloy (CRA) material, known as a cladding material, is economically suitable as the thinner layer enhances the corrosion-resistant abilities with increasing cost. Because of this, cladded pipe is extensively used in subsea pipelines and natural gas industries for conveying sour oil and gas, saltwater pipelines, water reinjection systems, process pipes in the chemical industry, saltwater pipes, water injection pipelines, inter-field pipelines, riser pipelines, flow lines, power plants, and marine applications.
CRA Materials for Cladded Pipe
An extensive range of stainless steel and non-ferrous alloy materials to suit the temperature requirements can be used as cladded pipe material. In normal industrial applications the following materials are found suitable as cladding materials:
The cladding material shall conform to ASTM A265, B898, B424, B443, B619, A240, A263, A264, B622, B675, B265, B551, etc. The thickness of the CRA layer is normally 0.25 mm to 6 mm.
Cladding material types and thicknesses can be selected to meet the specified environment.
API 5LD provides basic requirements for CRA cladded line steel pipe.
The main parameters that are considered while selecting a CRA material are:
Temperature
Chloride Concentration
Partial Pressure of CO2 and H2S
Environment pH
Presence or absence of Sulphur
Fig. 1: Cladded Pipe
Manufacturing of CRA Cladded Steel Pipes
Two common types of pipe cladding processes are available for bonding the CRA cladding pipe layer to the steel pipe:
1. Metallurgical bonding of cladding pipe:
The metallurgical bonding of the cladding can be achieved by various methods like Weld Overlay, explosion bonding, hot rolling, coextrusion, powder metallurgy, etc. Clad plates are utilized as raw materials. However, The main problem with metallurgical bonding is the high costs due to a limited number of suppliers for such a complex and demanding manufacturing process of metallurgical bonding the plates.
Weld Overlay Process
Weld Overlay is the most widely used metallurgical bonding process for pipe cladding. A Weld Overlay is also known as cladding, weld cladding, hard facing, or weld overlay cladding. In this process, one or more metals are joined together via welding to the surface of a base metal (backing steel) as a layer. Surfaces prepared by the weld overlay method can even be highly customized by layering and alloying multiple different materials together.
The weld overlay process is suitable for smaller as well as very large diameter pipe spools, flanges, and fitting. The main benefits that weld overlay pipe cladding provides are:
The weld overlay process can be applied to complex requirements.
It provides long life and high-reliability corrosion resistance to harsh environment applications.
Weld overlay is an economical way to provide excellent corrosion resistance for steel without jeopardizing design thickness.
Other Metallurgical Bonding Processes
For manufacturing cladded pipe by explosion bonding, two dissimilar materials are bonded with the help of pressure and heat produced by the explosion. The clad material is kept on top of the base material and then the explosive material is spread on it. Upon ignition of the explosive, the resultant thrust bonds the clad plate on the base plate underneath. Depending on the job requirements, various combinations of the clad plate and base plate thickness can be bonded.
Roll bonded cladding technique is usually used for the mid-range of pipe sizes (16″ to 24″). Some of the advantages of Roll-bonded metallurgical bonding cladding methods are:
It provides a better surface as compared with overlay welding.
Roll-bonded clad plates are an economical alternative to expensive high-alloy solid plates. An optimum combination is arrived at by the mechanical properties of the base material and the corrosion resistance of the cladding material.
As compared with solid plates, it has thinner wall thicknesses and better workability.
More homogeneous bonding and a wider range of dimensions compared with explosion cladding.
2. Mechanical bonding of Cladding Pipe:
Mechanical bonding of the CRA pipe and the base steel pipe is performed by using spring back variation using Hydroforming or full-length pipe expander. Hydroforming is more expensive than a full-length pipe expander.
Inspection of CRA Cladded Pipes is done using Ultrasonic Testing Methods.
Fig. 2: Typical CRA-clad pipe
Difference between Clad and Lined Pipe
Some of the differences between a cladding pipe and a lined pipe are listed below:
Cladded Pipe
Lined Pipe
Metallic material is used for cladding.
For lining, non-metallic material is used.
Weld Overlay or explosion bonding process.
Mechanical bonding process with adhesive
Suitable for high temperature and pressure applications.
Normally used in low-pressure and temperature applications
Complicated fabrication
Easy fabrication because of flanged joints.
Economically Costly
Comparatively cheaper.
Cladded Pipe vs Lined Pipe
What is the Reynolds Number? The Equation for Reynolds Number and Its Significance
In the field of fluid mechanics, understanding the behavior of fluids in motion is of utmost importance. One crucial parameter that helps characterize the flow regime is the Reynolds number. Named after the pioneering scientist Osborne Reynolds, this dimensionless number provides insight into the transition between laminar and turbulent flow. In this article, we will delve into the concept of the Reynolds number, its equation, significance, and how it influences fluid flow.
What is Reynold’s Number? Definition of Reynold’s Number
Reynolds Number is a very important quantity for studying fluid flow patterns. It is a dimensionless parameter and is widely used in fluid mechanics.Reynolds Number of a flowing fluid is defined as the ratio of inertia force to the viscous force of that fluid and it quantifies the relative importance of these two types of forces for given flow conditions.
The concept of Reynold’s number was introduced by George Stokes in 1851. However, the name “Reynolds Number” was given with the name of the British physicist Osborne Reynolds, who popularized its use in 1883. The Reynolds number depends on the relative internal movement due to different fluid velocities. For fluid flow analysis, Reynold’s number is considered to be a prerequisite.
Importance of Reynolds Number
Reynolds Number (Re) is a convenient parameter that helps in predicting if a fluid flow condition will be laminar or turbulent. We know that Reynolds Number (Re)=inertia force/viscous force.
When viscous force dominates over the inertia force, the flow is smooth and at low velocities; the Reynolds Number value is comparatively less and the flow is known as laminar flow. On the other hand, when inertia force is dominant, the value of the Reynolds number is comparatively higher and the fluid flows faster at higher velocities and the flow is called turbulent flow. At low Reynolds Number Values (Re<2100) the viscous force is sufficient enough to keep fluid particles in line making the flow laminar which is characterized by smooth and constant fluid motion. While at large Reynold Number values (Re>4000), the flow tends to produce chaotic eddies, vortices, and other flow instabilities making the flow turbulent. With an increase in Reynolds Number the turbulence tendency of the flow increases.
Fig. 1: Reynolds Number vs flow regimes
“2100<Reynolds Number (Re)<4000” indicates a flow transition from laminar to turbulent and the flow consists of a mixed behavior. However, note that the value of Reynolds number (Re) at which turbulent flow begins is dependent on the geometry of the fluid flow, which is different for pipe flow and external flow.
The Reynolds number associated with the laminar-turbulent transition is known as the Critical Reynolds Number. This laminar to turbulent transition is a highly complicated process, which is not yet fully understood.
The Equation for Reynolds Number
Mathematically, The Equation for the Reynolds number is represented as
Re=ρuD/μ
where
ρ is the fluid density Kg/m3)
D is a length scale that characterizes the scale of the flow motions of interest (m)
u is the fluid velocity (m/s)
μ is the fluid dynamic viscosity (Pa.s or N.s/m2 or kg/m.s)
the term μ/ρ is known as kinematic viscosity, ν (m2/s)
Hence the formula for Reynold’s number can be written as Re=ρuD/μ=uD/ν
The Reynolds number (Re) of a flowing fluid can easily be calculated by multiplying the velocity of fluid flow by the pipe’s internal diameter and then dividing the result by the kinematic viscosity of the fluid.
Components of Reynolds Number Formula
Let’s understand the components of the Reynolds Number Formula:
Inertial Forces: Inertial forces arise from the tendency of a fluid to resist changes in its state of motion. They depend on the density of the fluid (ρ) and the velocity of the fluid (u). A higher density or higher velocity will result in greater inertial forces.
Viscous Forces: Viscous forces, on the other hand, are the internal frictional forces between adjacent fluid layers that resist the flow. These forces depend on the dynamic viscosity (μ) of the fluid. A higher viscosity implies stronger viscous forces.
Characteristic Length (D): The characteristic length (D) represents a characteristic dimension of the object or the flow domain. It could be the diameter of a pipe, the chord length of an airfoil, or any other relevant length scale. The choice of characteristic length is crucial and depends on the specific flow situation.
Unit of Reynold’s Number
Let’s find the dimension of Reynold’s number. The Primary dimension of ρ is (M/L3) and the velocity is (L/T) Again the primary dimension of diameter/length is L and viscosity μ is (M/LT). Substituting all these values in the above-mentioned formula of Reynold’s number we get [{M/L3 * L/T * L}/ (M/LT)]=M*L*L*L*T/L3*T*M=MTL3/MTL3=1 Which means Reynolds Number is dimensionless or unitless. The same concept can be put forth as follows:
As the Reynolds Number is the ratio of two forces, there is no unit of Reynolds Number. So, Reynold’s Number is dimensionless.
Factors Affecting Reynolds Number
The main factors that govern the value of the Reynolds Number are:
The fluid flow geometry
Flow velocity; with an increase in flow velocity the Reynolds number increases.
Characteristic Dimension; with an increase in characteristic dimension the Reynolds number increases.
Fluid Density; with a decrease in fluid density the Reynolds number value decreases.
Viscosity; with an increase in viscosity the value of the Reynolds number decreases.
Fig. 2: Factors Affecting Reynolds Number
So, in one sentence we can conclude that Reynolds Number is directly proportional to Flow Velocity, Characteristic Dimension, and Fluid Density while inversely proportional to fluid viscosity.
Applications of Reynold’s Number
The Reynolds number plays a crucial role in fluid mechanics and has significant practical implications. Here are a few areas where the Reynolds number finds applications:
Flow Analysis and Design:
Understanding the Reynolds number is vital in the analysis and design of fluid flow systems. It helps engineers and scientists predict the behavior of fluids in pipes, channels, and around objects. By knowing the flow regime, appropriate design considerations can be made to optimize efficiency and minimize pressure losses.
Drag and Lift Forces:
The Reynolds number influences the drag and lift forces acting on objects moving through a fluid. In the case of aerodynamics, for instance, the Reynolds number determines the flow regime around an aircraft wing or an automobile, affecting factors such as lift, drag, and overall performance.
Heat Transfer:
The Reynolds number has implications for heat transfer processes. It helps in determining the convective heat transfer coefficient, which is crucial in applications such as cooling systems, heat exchangers, and thermal management.
Fluid Mixing:
The Reynolds number is a valuable parameter in understanding and controlling fluid mixing processes. It helps determine the efficiency and effectiveness of mixing operations in various industries, including chemical engineering, pharmaceuticals, and food processing.
Other Applications:
As Reynolds number is used for predicting laminar and turbulent flow, it is widely used as a design parameter for hydraulic and aerodynamic equipment. The Reynolds number for laminar flow is less than 2100. The value of the Reynolds number is a significant necessity for fluid flow analysis.
For the design of piping systems, aircraft wings, pumping systems, scaling of fluid dynamic problems, etc Reynolds number serves as an important design tool. To simulate the movement of any object in any fluid, the Reynolds Number is required.
Reynold’s number is used to calculate the value of the drag coefficient. In the calculation of pressure drop and frictional losses, the Reynolds number plays an important role. The following diagram (Fig. 3), known as the Moody chart provides a correlation between friction factor, Reynold’s Number, and Relative roughness and is widely used in solving fluid flow problems.
Fig. 3: Reynolds number in Moody Chart
Reynold’s number (Re) is also used to calculate the value of friction factor (f) using the Colebrook Equation as mentioned below:
Colebrook Equation for calculating friction factor using Reynold’s number
In the above equation, ε=Absolute Roughness.
Reynolds Number Values
The following table provides some typical Reynold Number values
Sr No
Item
Typical Reynolds Number
1
Laminar Flow
<2100
2
Turbulent Flow
>4000
3
Person Swimming
4 × 106
4
Blue Whale
4 × 108
5
Smallest fish
1
6
Atmospheric tropical cyclone
1 x 1012
7
Bacterium
1 × 10−4
8
Blood flow in the brain
1 × 102
9
Blood flow in the aorta
1 × 103
10
Fastest fish
1 × 108
Typical Values of Reynolds Number (Reference: wikipedia.org)
Reynolds Number for Laminar Flow
Laminar flow is the smooth flow in layers. There is little or no mixing and the fluid velocity is typically lower. The motion of the fluid particles is ordered without any cross currents. This is typically found in fluids of high viscosity and at lower velocities. The value of Reynold’s Number for Laminar flow is less than 2100.
Reynolds Number for Turbulent Flow
In turbulent flow, there is turbulence and unpredictable mixing. The velocity is high and fluids do not move in layers similar to laminar flow. Waves in the sea or river, storms, etc are examples of typical turbulent flow. The Reynolds Number for Turbulent flow is usually considered greater than 4000.
Critical Reynolds Number
The transition from laminar to turbulent flow is not abrupt but gradual. There is a critical Reynolds number, known as the critical Reynolds number, below which the flow remains laminar and above which it becomes turbulent. The specific value of the critical Reynolds number depends on various factors such as the geometry of the object, surface roughness, and fluid properties.
Low and High Reynolds Number
At low values of Reynolds Number Re<<1, the inertial effect becomes negligible. The flow behavior is dependent on the viscosity and the flow is stable. Whereas when the Reynolds Number Re is very very high, the viscous effects are negligible. The fluid flow behavior depends on the momentum of the fluid and the flow is unsteady.
Conclusions
The Reynolds number provides valuable insight into the flow regime of fluids and the transition from laminar to turbulent flow. By considering the interplay between inertial and viscous forces, engineers and scientists can better predict and analyze fluid behavior in various systems. Understanding the Reynolds number is essential for optimizing design, predicting performance, and ensuring efficient and safe operation of fluid systems across numerous fields of application.
What is Radiographic Testing? It’s Types, Principles, Procedures, Standards, Advantages, and Disadvantages
Radiographic testing (RT) is a non-destructive testing (NDT) method widely used to assess the integrity of materials and structures without causing damage. This technique plays a critical role in industries such as welding, aerospace, automotive, manufacturing, pipelines, and construction, ensuring safety and quality through precise evaluations. In this article, we’ll explore the principles, types, advantages, applications, and safety considerations of radiographic testing.
1. What is the Radiographic Testing?
Radiographic testing, or radiographic examination, is a non-destructive testing (NDT) method for examining the internal structure of any component to identify its integrity. Radiographic Testing or RT uses x-rays and gamma-rays to produce a radiograph of the test specimen that shows changes in thickness, defects or flaws, and assembly details to ensure optimum quality. Radiographic testing of welds to ensure weld quality is a widely used industry practice. Radiographic testing in welding is a highly dependable way to detect weld defects like cracks, porosity, inclusions, voids, lack of fusion, etc. in weld interiors. Because of its high dependability, radiographic testing is widely used in the oil & gas, aerospace, transport, military, automotive, manufacturing, offshore, petrochemical, marine, and power generation industries.
2. Radiographic Testing Principle
In Radiography Testing, the part to be tested is placed between the radiation source and a piece of sensitive film or detector. Once the x-ray or gamma-ray radiation is started, the test part will hinder some of the radiation by its material density and thickness. Thicker and denser material will allow less radiation to pass through the specimen. The film (or an electronic device) records the amount of radiation (known as a radiograph) that reaches the film through the test specimen. By studying the radiograph data, defects can easily be recognized. If the material is sound without any defect, entire rays will evenly pass through the material. But for materials containing flaws, rays passing through the flaws will get absorbed to a small extent due to the change in density.
Defects in parent metal reduce its density and hence they transmit radiation much better than the sound metal. Hence the radiograph film appears to be darker in the area exposed by the defects.
The penetration power of rays is dependent on the energy of the radiation. Radiation with higher energy can penetrate thicker and denser materials. As high-energy x-rays and gamma-rays are highly radioactive, local rules must be strictly followed.
In radiographic testing, defects are detected using thickness variation. So, the larger the variation, the easier the defect is to detect. But when the path of rays is not parallel to a crack, the thickness variation is less, and thus the crack may not be visible. That’s why it is always suggested to perform radiographic testing by sending rays at various angles.
In industrial radiography, various imaging techniques are employed to display the final results. These include:
Film Radiography
Real-Time Radiography (RTR)
Computed Tomography (CT)
Digital Radiography (DR)
Computed Radiography (CR)
Each of these methods offers distinct advantages, catering to different inspection needs and preferences.
Industrial radiography utilizes two primary radioactive sources: X-rays and Gamma rays. Both types use high-energy, short-wavelength versions of electromagnetic waves, allowing for effective penetration of materials. Due to the inherent risks associated with radioactive materials, strict adherence to local safety regulations is crucial during operations.
Computed Tomography (CT) is one of the advanced non-destructive testing (NDT) methods offered by TWI for industrial applications. This technique generates both cross-sectional and 3D volume images of the inspected object.
CT provides a significant advantage over traditional 2D radiography by eliminating overlay, allowing for a clearer examination of the internal structure of components. This capability enables a thorough analysis of various parts, facilitating improved detection of internal features and flaws.
Fig. 1: Radiographic Testing
2.1 Types of Radiographic Sources
Radiographic testing utilizes various sources, including:
Conventional Sources
Micro-focus X-ray Equipment
Nano-focus X-ray Equipment
Linear Accelerators (Linac)
Betatrons
Synchrotrons
Isotropic Sources such as Iridium-192, Cobalt-60, Thulium-170, Ytterbium-169, Caesium-137, and Selenium-75.
2.2 Types of Radiographic Detectors
There are several types of radiographic detectors available, including:
Radiographic Films with grain sizes from D4 to D7
Radiographic Image Intensifiers
X-ray Sensitive Vidicons
Fluorescent Screens and Charged Coupled Devices (CCDs)
Imaging Plates
Digital Flat Panels, such as Amorphous Selenium Panels and Amorphous Silicon Panels
Linear Diode Arrays
2.3 Key Factors in Radiographic Imaging
A crucial aspect of radiographic imaging includes the contrast of the subject, film contrast, and image definition. These factors are influenced by several elements:
Energy Utilized in the Process
Wave Intensity
Scattered Radiation resulting from the interaction of beams with the specimen
Focal Spot Size
Characteristics of the Detector Used
3. Radiographic Testing Procedure
Depending on project requirements the radiographic testing procedure will vary a little. The following paragraphs provide sample procedural steps for radiographic testing.
Step 1- Surface Preparation: Surface irregularities must be removed so that they can not mask or confuse the image as a defect. The finished surface of all butt welded joints should be flushed with the base material.
Step 2- Selecting the right radiation source and radiographic film: Depending on radiographic sensitivity and material thickness radiation source (x-ray or gamma-ray) must be decided. Fine-grain high-definition radiographic films can be used.
Step 3- Selection of Penetrameter: As per SE 142 or SE 1025 (for whole type) and SE-747 (for wire type), ASME V & ASME Sec VIII Div I, whole type or wire type penetrameter need to be selected.
Step 4-Radiographic testing technique: Single or Double wall exposure technique is used. Source-to-object and object-to-source distances must be established beforehand.
Step 5- Defect inspection and removal: The radiograph is to be studied for probable defects and repaired if the defect is observed.
Step 6- Recording: All data need to be properly recorded.
4. Acceptance Criteria for Radiographic Testing
For process Piping: The acceptance criteria for radiographic testing shall be as per table 341.3.2 A of ASME B31.3 for normal fluid service, with the exception of piping class E.
For structural steel: The acceptance criteria for the non-tubular structure shall be in accordance with the requirement section 6.12.1 of AWS D1.1 and for tubular joints section 6.12.3 of AWS D1.1
5. Types of Radiography
Radiographic testing (RT) encompasses various techniques, including conventional and digital methods, each with its own advantages and limitations.
5.1 Conventional Radiography
Conventional radiography relies on sensitive film that reacts to emitted radiation, capturing an image of the tested part. This image can be analyzed for potential damage or flaws. However, a significant drawback is that each film can only be used once, and the processing and interpretation of the images can be time-consuming.
5.2 Digital Radiography
In contrast to conventional methods, digital radiography uses digital detectors to display radiographic images on a computer screen almost instantly. This technique significantly reduces exposure time, enabling quicker interpretation of results. Digital images are generally of higher quality, allowing for the identification of material flaws, foreign objects, weld repairs, and corrosion under insulation (CUI). Common digital radiography techniques in the oil and gas, as well as chemical processing industries, include computed radiography, direct radiography, real-time radiography, computed tomography, and automated radiographic testing.
5.3 Computed Radiography
Computed radiography (CR) employs a phosphor imaging plate instead of film. While quicker than conventional film radiography, it is slower than direct radiography. CR involves capturing an image on the phosphor plate and converting it into a digital signal for visualization on a computer. Although image quality is generally fair, it can be enhanced using various tools. However, caution is necessary to ensure that minor defects are not obscured by adjustments.
5.4 Direct Radiography
Direct radiography (DR) is similar to CR but uses a flat panel detector to capture images directly, which are then displayed on a computer screen. DR offers faster imaging and higher-quality results, but it comes with a higher cost compared to CR.
5.5 Real-Time Radiography
Real-time radiography (RTR) allows for instantaneous image viewing and analysis. This method emits radiation through an object, interacting with a phosphor screen or flat panel detector containing microelectronic sensors. The resulting digital image reflects varying radiation levels; brighter areas indicate thinner or less dense sections, while darker areas correspond to thicker components. RTR eliminates the need for physical storage, making it easier to archive and transfer images. However, it may exhibit lower contrast sensitivity, uneven illumination, and other issues that can affect image quality.
5.6 Computed Tomography
Computed tomography (CT) captures numerous 2D radiographic scans to create a detailed 3D image of the component. In industrial applications, CT can be performed in two ways: one involves rotating the radiation source and detector around a stationary component, ideal for larger parts, while the other method rotates the component itself, suitable for smaller or more complex geometries. Though CT requires significant time, expense, and data storage, it delivers highly accurate, repeatable images, minimizing the potential for human error.
5.7 Automated Radiographic Testing
Automated radiographic testing (ART) was designed for faster, safer, and more consistent detection of CUI and internal corrosion in above-ground piping and pipelines. ART utilizes a semi-autonomous motion control platform that carries low-level X-ray emitters, projecting onto CMOS and photon detectors that produce radiographic maps in seconds. This technology enables robotic services to efficiently radiographically map large areas without disrupting service or removing insulation, providing immediate digital images for on-site evaluation.
6. Codes and Standards for Radiographic Testing
Widely used codes and standards for radiographic testing are:
ISO 5579, Non-destructive testing – Radiographic examination of metallic materials by X- and gamma-rays – Basic rules
ASME SE: Standard Method for Controlling Quality of Radiographic Testing.
ASME SE 94: Recommended Practice for Radiographic Testing
ASTM E 801, Standard Practice for Controlling Quality of Radiological Examination of Electronic Devices
API 1104, Welding of Pipelines and Related Facilities: 11.1 Radiographic Test Methods
AASME SE V: Boiler and Pressure Vessel – Non-Destructive Testing.
ASTM 1161, Standard Practice for Radiologic Examination of Semiconductors and Electronic Components
ISO 10675-1, Non-destructive testing of welds – Acceptance levels for radiographic testing – Part 1: Steel, nickel, titanium, and their alloys
SNT-TC-1A: Recommended Practice for Personnel Qualification and Certification in Non-destructive Testing.
ASTM E 592, Standard Guide to Obtainable ASTM Equivalent Penetrameter Sensitivity for Radiography of Steel Plates
ASTM E 1030, Standard Test Method for Radiographic Examination of Metallic Castings
ASTM E 1815, Standard Test Method for Classification of Film Systems for Industrial Radiography
EN 12681, Founding – Radiographic examination
ASTM E 1032, Standard Test Method for Radiographic Examination of Weldments
ISO 4993, Steel and iron castings – Radiographic inspection
7. Advantages of Radiographic Testing
Radiographic testing (RT) offers numerous advantages over other non-destructive testing (NDT) methods, particularly in its ability to assess internal structures and complex geometries. Some of the key advantages of radiographic testing are
Assembled components can easily be inspected.
The surface preparation requirement is minimal.
RT is known for its exceptional accuracy, capable of detecting even minute flaws that might go unnoticed with other techniques. Both surface and subsurface flaws can be detected.
Easily verify internal defects on complex items/structures
Automatically detect and measure internal flaws
Dimensions and angles of the sample can be measured without sectioning.
Radiographic testing is one of the best NDT methods in lieu of golden joints.
RT can be applied to a wide range of materials, making it suitable for various applications across different industries.
The results from radiographic testing are visually represented and can be permanently documented, either digitally or on film. This eliminates concerns about data loss and simplifies analysis.
X-rays and gamma rays have excellent penetration abilities, allowing them to reveal detailed internal structures within the test material.
Unlike some NDT methods that may misinterpret surface anomalies, RT can accurately identify internal defects, providing clear insights into their nature, size, and depth. This simplifies the process of detecting fabrication errors.
8. Disadvantages of Radiographic Testing
The main disadvantages of radiographic testing are
Highly hazardous, so proper care must be exercised.
The high degree of skills and experience required.
Costly affair; the specialized equipment required for RT, designed to use penetrating radiation, can be expensive to acquire and maintain.
Slow process.
Two-sided access to components is required.
Interpreting the depth of detected defects can be challenging, as radiographic results may not provide clear information on the depth of indications.
9. Applications of Radiographic Testing
Industrial radiography is mostly used for inspection purposes. The industries that make frequent use of RT are
Weld Inspection: Commonly used to evaluate weld quality and detect defects in pipelines, pressure vessels, and structural components.
Casting Inspection: Ensures the integrity of cast components by identifying internal voids or inclusions.
Aerospace Components: Critical in the aerospace industry for inspecting aircraft parts and ensuring safety standards.
Automotive Industry: Used to inspect components for structural integrity and safety, such as engine parts and chassis.
Nuclear Industry: Plays a vital role in ensuring the safety and integrity of nuclear reactor components.
Military Defense: Critical for evaluating the integrity of military equipment and munitions, ensuring they meet high safety and performance standards.
Offshore Industries: Essential for inspecting pipelines, risers, and structural components in challenging marine environments, helping to prevent leaks and failures.
Marine Industry: Used to assess the condition of ship hulls, propellers, and other critical parts, ensuring the safety and reliability of maritime operations.
Power Generation Industry: Employed to inspect components in power plants, including boilers and turbines, to maintain operational efficiency and safety.
Petrochemical Industry: Vital for examining pipelines, vessels, and storage tanks to prevent leaks and failures in the transportation and processing of hazardous materials.
Waste Management: Used to inspect waste containers and processing equipment, ensuring compliance with safety regulations and preventing contamination.
Manufacturing Industry: Widely applied to inspect castings, welds, and assembled parts, helping to maintain quality control throughout the production process.
Transport Industry: Utilized to ensure the safety and reliability of transport components, including railways and road infrastructure, by detecting potential flaws.
Medicine Industry: Radiographic testing plays a critical role in the medical industry, contributing to both diagnostics and treatment.
Radiographic testing is a powerful non-destructive technique that plays a critical role in ensuring the safety and reliability of materials across various industries. Its ability to detect internal defects without damaging components makes it indispensable for quality assurance and regulatory compliance.
