Horizontal Directional Drilling

THE HDD PROCESS
The use of Horizontal Directional Drilling to install crossings under a vast range of surface obstacles was developed in the 1970s combining techniques used in conventional road boring and those used in oil and gas directional drilling. This method is currently used to install pipelines for oil, water, natural gas and waste water as well as conduits for power and fiber optic cables. The main objective is to install such services without using traditional trenching methods, helping to avoid any unnecessary environmental impact and provide added security.
The Horizontal Directional Drilling process generally includes four stages: Site Investigation and Design – Project designs start with the gathering of necessary information.  This information includes the site survey, including locations of existing pipelines and services, and a geotechnical site investigation.  This will determine the tools necessary to successfully drill the crossing and determine the design. Pilot Hole Drilling – The pilot hole is drilled from the entry point to the exit point following a previously designed profile and alignment. The drilling tools and rig equipment selected for each job is largely determined based on the results of the geotechnical investigation and the size of the crossing (length and diameter). During the pilot hole drilling, a directional guidance system is used to navigate the pilot hole along its pre-designed profile. Click here to view illustration Hole Enlargement – In small diameter crossings the pipeline may be directly installed in the pilot hole. However in most cases pilot hole enlarging, known as “pre-reaming,” will be necessary. Pre-reaming is required to provide a bore diameter large enough so that the pipeline can be installed in the drilled crossing. Based on the final desired diameter and soil conditions this process may include one or more stages. Click here to view illustration Pullback – Once the drilled hole has been enlarged to the required diameter and cleaned adequately, the pipeline is installed. When applicable, the pipeline is pre-assembled in a single string and placed on rollers prior to pullback. For pullback, a reamer is connected to the drill pipe. Behind the reamer a swivel is connected allowing the drill pipe to rotate the reamer without allowing the transfer of torque to the product pipe. The drill pipe is then pulled back towards the entry point until the pipeline is fully installed. Click here to view illustration
Why HDD? Less invasive than the traditional open cut. Requires a relatively short set up time. Surface disruption is minimized. More secure than above ground or trenched installations. Can make deep installations and avoid surface obstacles such as rivers, railways, or highways.
Intersect HDD Installations The intersect method is utilized when the length, the soil conditions, or a combination of the two do not allow the use of a single drilling rig to accomplish the bore.  In an intersect HDD installation, two directional drilling rigs (a primary and secondary drilling rig) are placed at opposite ends of a project site and start drilling toward each other guided by a precision underground magnetic tracking device. Once the bores are within a pre-determined distance from each other, the primary rig advances its drill string, following behind the secondary rig's retreating downhole assembly.  The advancing drill string is then steered toward and ulimately "falls" into the vacated borehole produced by the retreating drill string, creating a continuous single borehole.  The borehole is then reamed to the appropriate size and product pipe is pulled. Click here to view an Intersect HDD Installation Illustration
Shore Approach While the basic steps of a shore approach remains the same as a conventional HDD crossing (i.e. pilot, ream, pullback), there are additional challenges in working within a marine environment. Pilot Hole Drilling – The drilling tools and rig equipment selected for each job are largely determined based on the results of the geotechnical investigation and the size of the crossing (length and diameter). During the pilot hole drilling, a directional guidance system is used to navigate the pilot hole along its pre-designed profile.  In some cases, the pilot hole is drilled from the primary rig at the entry point onshore to the secondary rig located at the exit point offshore following a previously designed profile and alignment.  Click here to view Illustration Shore Approach #1 Hole Enlargement – In small diameter crossings the pipeline may be directly installed in the pilot hole.  However in most cases pilot hole enlarging, known as “pre-reaming,” will be necessary.  Pre-reaming is required to provide a bore diameter large enough so that the pipeline can be installed in the drilled crossing.  Based on the final desired diameter and soil conditions, this process may include one or more stages.  Click here to view Illustration Shore Approach #2 Pullback – Once the drilled hole has been enlarged to the required diameter and cleaned adequately, the product pipe, which will have been preassembled offshore (or assembled onshore and then towed offshore), is readied for installation.  The pipeline string is aligned behind the underwater borehole exit point and then pulled into the hole towards the onshore drill rig until installation is complete.  Variations to this basic scenario may be needed to fit actual conditions. Click here to view Illustration Shore Approach #3 Sumber: http://www.coedrilling.com.au/horizontal-directional-drilling-process.php

Pipeline Risk Assessment/Drop object analysis/Pullover loads on Pipeline/Hooking loads on pipeline

What is Risk Assessment?

Risk assessment is a process used to evaluate unwanted consequences and the likelihood of those consequences occurring. The purpose of risk assessment is to develop information that allows organizations to make decisions that reduce or eliminate unwanted consequences by changing their likelihood, their adverse impacts, or both.

For instance, aircraft manufacturers analyze the performance effects of different aircraft designs to minimize the likelihood of crashes. Government agencies evaluate the effects of emissions from industrial plants, or motor vehicles, in order to develop regulations that limit emissions and minimize adverse impacts to the public and the environment.

The terms “risk analysis” and “risk evaluation” are often used interchangeably with “risk assessment”.

What is risk?

Risk is a concept that describes and measures the combination of the likelihood of a negative outcome and the severity of consequences that result from that outcome. The higher the risk number, the more “risky” is the combined likelihood and severity of a particular event.

Likelihood is measured as probability ( a number between 0 and 1 that represents the chance of some consequence occurring) or as frequency (a number that represents how many times a consequence occurs during a fixed time period).

Consequence is measured in a variety of ways, depending on the nature of the consequences being considered. For example, if the consequences involve human health or safety, then consequences may be measured by fatalities or injuries. If consequences involve environmental damage, they may be measured by the cost required to repair the damage and restore the affected environment.

How do pipeline operators use risk assessment to enhance pipeline safety?

Risk assessment is used to address issues pertaining to safety, environmental protection, financial management, project or product development, and many other areas of business performance. In the pipeline industry, risk assessments are utilized for many of these same reasons. For the purposes of this fact sheet, however, we are addressing risk assessment related to pipeline safety – that is, protecting the public, property, and the environment from pipeline failures.

Risk assessments of this kind begins by looking at the different ways a pipeline can fail and release its contents – such as oil or natural gas – into the environment. Factors that can lead to pipeline failure are referred to as pipeline failure threats . For example, a pipeline can leak because corrosion weakens the steel in the pipe. Failures also occur as a result of excavation equipment striking the pipe. Identifying potential threats to a pipeline requires looking at the factors that cause failures as well as looking for unique factors that could lead to failure at a particular location, whether or not that particular failure has occurred or been observed before.

The next step in risk assessment is to assess the likelihood that each threat could lead to a failure at a particular location on the pipeline. This assessment is performed by looking at the specific characteristics of the pipeline at any given location, along with the unique characteristics of the area around the pipeline. For example, the susceptibility of the pipeline to failure due to corrosion is dependent on numerous characteristics, such as the type and condition of the pipe’s coating, the effectiveness and operability of the operator’s corrosion control equipment, and the soil conditions surrounding the pipe.

As another example, the susceptibility of a pipeline to third-party excavation damage is dependent on characteristics such as the extent and type of excavation or agricultural activity along the pipeline right-of-way, the effectiveness of the One-Call System in the area, the amount of patrolling of the pipeline by the operator, the placement and quality of right-of-way markers, and the depth of cover over the pipeline. In all cases, different threats will exist at different locations along the pipeline.

The next step is to assess the types of consequences that could result from a pipeline release at a specific location, along with the potential severity of those consequences. For example, failures of pipelines in remote areas, where people do not live or congregate, will likely result in lower impacts than failures in areas of dense residential or commercial development. Similarly, failures in areas sensitive to environmental damage, such as the locations of drinking water sources or endangered species’ habitats, have higher environmental consequences than areas without these features.

The final step in risk assessment for a pipeline is to use the results of the likelihood and consequence assessments to determine the overall risk at each pipeline location. This allows the operator to ensure that sections identified as having the highest risk are assigned top priority for actions that will reduce the likelihood of a release, reduce its potential consequences, or both.

The results of the likelihood assessment also provide the operator with information on the significance of different pipeline threats at different locations, allowing them to carry out actions that reduce the likelihood of a pipeline failure. For example, an operator may choose to conduct internal inspections on those pipeline sections that are shown to be most susceptible to corrosion, to identify where corrosion might be occurring, and to repair any damage before the pipe fails.

The results of the consequence assessment provide the operator with information on the significance of consequences of accidents at different locations, so that operators can carry out steps to reduce or eliminate those consequences. For example, an operator may place specialized emergency response equipment at an environmentally sensitive site to allow for quick response should a pipeline release occur.

What are the requirements for risk assessment by pipeline operators?

It is important for pipeline operators to be keenly aware of threats and potential consequences of accidents along the entire length of their pipelines, and to employ rigorous assessment as a tool to manage those risks.

The federal pipeline integrity management regulations for hazardous liquid pipelines ( §195.452) and natural gas pipelines ( §192.901- §192.951) require operators to perform risk assessments of their pipelines to:

• Ensure that integrity assessment methods (internal inspection, pressure testing, direct assessment, etc.) are employed to address significant threats on pipeline segments.
• Ensure that integrity assessments of the highest risk segments are scheduled with priority over lower risk segments.
• Ensure that assessments of threats and potential consequences are conducted to define, evaluate, and implement additional measures that address significant threats to the pipeline (e.g., conducting depth-of-cover surveys and correcting any deficiencies), or reduce potential consequences of failures (e.g., installing additional valves on the pipeline to reduce the amount of liquid or gas that might be released should a failure occur).

Sumber: https://primis.phmsa.dot.gov/comm/FactSheets/FSRiskAssessment.htm

Linepipe Manufacture

Line Pipe

Line pipe is manufactured from high-strength carbon steel, and is made to strict engineering and metallurgical specifications developed by the American Petroleum Institute (API).

One particular standard, API Specification 5L, defines requirements for pipe made to transport natural gas, oil and water.  This specification includes standards for the dimensional, physical, mechanical, and chemical properties of the carbon steel.  Several pipe mills in North America and around the world manufacture API 5L line pipe for the natural gas industry.  Pipe mills produce two types of line pipe: seamless and welded.

Seamless pipe is formed from a cylindrical bar of steel that is heated to a very high temperature and then is pierced with a probe to create the hole through the cylinder.  Rollers size the cylinder to produce the proper diameter and wall thickness. This technique is used to make small diameter pipe, from 0.5 inches to 24 inches in diameter.

Most pipe produced for interstate natural gas pipelines is the welded variety, because interstate systems require larger diameter pipe.  Pipe mills manufacture line pipe by forming a steel plate or coil into a cylindrical shape, and closing the seam using a welding process.  The mill evaluates the quality of the weld seam using ultrasonic and/or radiological inspection methods and pressure tests each joint of pipe to levels significantly higher than the eventual operating pressure of the pipeline.  

The pipe is further tested to ensure that it meets all requirements of steel chemistry, strength and toughness, and dimensional characteristics.  Mills that produce line pipe to API specifications meet the most stringent criteria for steel making and pipe production technologies to ensure safe, reliable pipeline service.  The gas pipeline industry maintains the manufacturing and test records of the pipe for the life of the pipeline.

Pipeline Size and DesignThe size of interstate pipelines varies, but in most cases a mainline, the principal pipeline that delivers natural gas, ranges from 16 to 48 inches in diameter.  Other smaller pipelines called laterals deliver gas to the mainline or take gas from the mainline and range from six to 16 inches in diameter.

The volume of gas to be delivered and the pressure at which the pipeline will be operated determines the pipeline’s ultimate diameter.  In order to meet customer delivery requirements most interstate gas pipelines operate at a pressure of at least 600 pounds per square inch (psi), but typically at about 1,000 psi.

The thickness of the pipeline is determined by the maximum operating pressure (MAOP), and is based on published industry standards and federal regulations. The pipeline incorporates a design safety factor, prescribed by U.S. Department of Transportation (DOT) regulations, that is related to the type of construction and population density along the pipeline route.

Sumber: http://www.ingaa.org/cms/112.aspx

Underwater Welding by Diver

1. How to Weld Underwater

   Underwater welding is a process whereby metals are melted together underwater to either repair a structure or create a new structure. Used on oil wells, ships, and other underwater structures, underwater welding is done by one of two methods. The first is hyperbaric welding, in which a structure is created around the weld and a pressurized environment created. The second is arc welding, in which the welding electrode contains a flux coating that releases gases to preserve the integrity of the weld. Because of the dangers of shock, explosion and poisoning, underwater welding is only performed by professionals with both diving and welding certifications.

1. Method 1: Hyperbaric Dry Welding
2. 
   1
   Identify the site and material of the joint to be welded and clean it. Most underwater welds involve steel, but metals may vary.
3. 
   2
   Prepare a chamber to place around the joint (each joint should have a separate chamber). Chambers range in size - some are large enough to fit several welder-divers, others are only small enough for the welding electrode.
4. 
   3
   Introduce gas into the chamber and pump out the water.
   

   • A typical gas mixture uses helium and oxygen, but requirements vary based on the specific joint to be welded. The pressure of the chamber should be slightly above that of the surrounding water.
5. 
   4
   Run a power supply to the chamber and set up a port for your electrodes.
   

   • Multiple electrodes will likely be required, and should be placed in advance in front of the area of the joint to be welded.
6. 
   5
   Dive to the weld site.
7. 
   6
   Turn on the power supply and weld the joint from outside the chamber.
8. 
   7
   Turn off the power supply as soon as the welding is done.

1. Method 2: Wet Welding

1. 
   1
   Investigate and clean the joint to be welded; identify the types of metals involved.
2. 
   2
   Prepare the adequate electrodes, plan out the order of welding and dive to the weld site.
3. 
   3
   Weld the joint, ensuring that the flux coating of the weld is coming off as expected, and that too much hydrogen is not approaching the joint.
4. 
   4
   Turn off the power supply as soon as the welding is done.

Tips:

• In addition to underwater hyperbaric welding and underwater arc welding, a common way of welding joints on surfaces underwater is to bring the surface onto dry land, create a pressurized chamber around the joint, and use a hyperbaric dry welding process. This eliminates the need for diving while still reaching normally underwater locations.

Warnings: 

• Because underwater welding involves two dangerous activities--welding and diving--years of instruction are usually needed before attaining competence. When learning how to weld underwater, do not attempt it if you are only comfortable as a welder or as a diver.
• Explosions can occur when pockets of hydrogen or oxygen build up and are exposed to a flame. Ensure that there is a method for venting built-up hydrogen and oxygen, and review all safety procedures beforehand.
• Underwater welding is only done with special electrodes designed for prolonged contact with water. Check that all electrodes and power supplies are adequately insulated.
• Poisoning from nitrogen or other gases can cause permanent injury or death while welding underwater. Divers should always have an external or back-up air supply and should use a depressurizing chamber when returning to the surface.

Sumber: http://www.wikihow.com/Weld-Underwater

Pig Trap/Pig Launcher/Intelligent Pig

Pig Trap Design And Assessment Considerations

A pig trap must be designed to match the pipeline section design specifications. The mechanical design characteristics of the pig trap should meet or exceed the design pressure, have the same design factor, have compatible material type, be designed using the same design code and be suitable for the same temperature range as the pipeline section that it serves.

Also, a pig trap must be dimensionally suited for the type of pigging that is expected on the pipeline section. The critical lengths of the barrels and line size pipe sections must be long enough to accommodate the longest pig that will be used in the pipeline section.

When deciding where to locate a pig trap, there are various things to consider. The pig trap should not be placed near any open flames or ignition sources. Many building codes and pipeline companies have rules and regulations about what type of powered equipment is allowed within certain distances of an opening to the pipeline such as a closure door. If the pig trap is to be located in an area where horizontal space is not at a premium (such as on an offshore platform or a refinery), then care should be taken to provide sufficient work space adjacent to the closure door for pigging operations. These operations can take the form of loading and unloading long inspections pigs, removal of liquids and debris from the pipeline and into a waste container, installation and operation of a temporary separator, etc.

Another consideration that is important to the safe and efficient operation of a pig trap is how the barrel is oriented at the pigging station. Any valves or instrumentation associated with the operation of the pig trap should be given adequate space to provide routine maintenance or replacement. The closure door should face away from other equipment and places where people typically congregate (i.e. break areas, parking lots, etc.). There have been rare occurrences where pigs have shot out of pig traps and damaged equipment, as well as, injured people. The oversized pipe section of a pig trap is not named barrel by coincidence.

In recent years, the energy industry has become increasingly focused on what effect its operations are having on the environment. The placement of a pig trap is also a concern in this area. When a pig trap is vented or a closure door is opened, forethought should be taken to minimize or eliminate the occurrence of hazardous contaminants within a pipeline from reaching the outside atmosphere or contaminating the nearby ground or water.

Pipeline companies that operate large-diameter pipelines should consider the use of material-handling equipment when it comes to conducting pigging operations. Mandrel or spherical pigs used in a pipeline that is 20 inches in diameter or large can be too heavy or awkward for one or two people to handle safely. In addition, even small-diameter inspection tools are typically too heavy and long for one or two people to easily manipulate into or out of a pig trap. There are various designs of pig trays available on the market. Some pig trays have wheels while others are stationary. There are other pig trays that have automation for pushing a pig into or pulling a pig out of a pig trap. Many pig trays are fitted with drip pans for collecting liquids or fine debris that may fall off of a pig once it is out of the receiver. In some cases, lifting equipment may be necessary to move large pigs into position. Jib cranes, gantry cranes and fork lifts are all examples of pig-handling equipment.

Pig traps and pigging systems should be designed according to the same design codes as the pipeline to which they are connected. The predominant codes used for pipeline design in many countries are written by ASME. The ASME codes commonly encountered in the pipeline industry are ASME B31.4 which governs the design of liquid pipelines; ASME B31.8 which governs the design of gas pipelines; ASME B31.3 which governs the design of process piping and ASME Section VIII, Div. 1 and 2 which governs the design of pressure vessels (sometimes referred to as the Boiler Code). There are other codes in use that govern the design of pig traps such as CSA Z-662 in Canada or ASME B31.11 for slurry pipelines.

It is helpful to the purchaser of pipeline equipment to understand some of the differences among the commonly used ASME codes. ASME B31.4 – Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids (crude oil, liquid petroleum gas, anhydrous ammonia, alcohols and carbon dioxide) allows for design with certain steel materials – ASTM A694 F42 to F70, A707 L3 CL3, A105, A350 LF2, A182 F316, A182 F51 (Duplex) and others; the design maximum allowable stress values are determined by design factors (0.72 or 0.6) multiplied by specified minimum yield strength (SMYS) of material; Pipe Wall Thickness Formula: wt = PD/2SF (wt=wall thickness; P=design pressure; D=pipe diameter(OD); S=allowable stress; F=design factor); based upon the allowable hoop stress of the material in question; welding standard is per API 1004.

ASME B31.8 – Gas Transmission and Distribution Piping Systems. Gas (not gasoline) as used in this code commonly refers to natural gas, manufactured gas and liquefied petroleum gas distributed as a vapor. This code allows for design with similar materials as in ASME B31.4. Design maximum allowable stress values are determined by design factor (0.8, 0.72, 0.6, 0.5 or 0.4) multiplied by SMYS of material. Design factors are related to population density in proximity of the pipeline. Pipe Wall Thickness Formula: wt = PD/2SF (wt=wall thickness; P=design pressure; D=pipe diameter(OD); S=allowable stress; F=design factor); based upon the allowable hoop stress of the material in question. Welding standard is per API 1004.

ASME B31.3 – Process Piping (has been referred to as refinery piping) Allowable materials are restricted to B31.3 “listed” materials – usually A105, A350 LF2, A182 F316. Some commonly used high-yield materials (i.e. A694 & A707) are not permitted under this Code. Design maximum allowable stress values are determined by the lesser of (1/3 x Su(tensile strength)) or (2/3 x Sy(yield stress)); the allowable stress values are found in B31.3 as “tabulated” values. Overall, material thicknesses calculated using B31.3 tend to be more conservative or thicker than those calculated using B31.4 or B31.8. Pipe Wall Thickness Formula: wt = PD/2(SE+PY) (wt=wall thickness; P=design pressure; D=pipe diameter(OD); S=allowable stress; E=quality factor; Y=coefficient) ; based upon the tensile strength of the material. Welding standard is per ASME Section IX.

ASME Section VIII Division 1 – ASME Boiler & Pressure Vessel Code Rule for Construction of Pressure Vessels. Allowable materials are restricted to ASME Section II “listed” materials – usually SA105, SA350 LF2, SA182 F316. Some commonly used high-yield materials (i.e. A694 & A707) are not permitted under this Code. Design maximum allowable stress values are found in ASME Section II as “tabulated” values. Overall, material thickness calculated using ASME Section VIII Div. 1 tend to be more conservative or thicker than those calculated using B31.3. Pipe Wall Thickness Formula: wt = PR/2(SE-0.6P) (wt=wall thickness; P=design pressure; R=pipe radius(inside radius); S=allowable stress [lesser of (Su(tensile strength) divided by 3.5) or (2/3 multiplied by Sy(yield stress))]; E=quality factor) ; based upon the tensile strength of the material. U Stamp – the official Code U Symbol for stamp (marking) on the vessel or closure to denote inspection and testing in compliance with Code requirements.

All of the codes discussed can be used to design pig traps. Inspection criteria vary among these different codes. Generally, given the same pipeline design parameters, a pig trap designed from ASME B31.3 will tend to be costlier than for one designed from ASME B31.4 or B31.8 because of the difference in material grades and thicknesses. In addition, a pig trap designed from ASME Section VIII Div.1 will tend to be more expensive than one designed from ASME B31.3 for the same reasons.

Pig Trap/Pigging System Assessments
Like any other piece of equipment connected to the pipeline, pig traps should be assessed at regular intervals for various reasons. The pipe and fittings that make up a pig trap will age and deteriorate over time. Pipeline companies may acquire existing pipelines with pig traps and it will be important to know the condition of these used assets. Some existing pipelines undergo a change in use whether it has to do with a reversal of flow direction or a change in product being transported. Existing pig traps can change the way they are used. A pig trap sized for cleaning pigs may need to be modified so that it can accommodate inspection pigs. A launcher may need to be changed from a manually operated pigging system to an automated pigging system.

A receiver may need to be modified so that it can receive more than one pig at a time. The initial design of the pig trap may be inappropriate for the current pipeline conditions. At some point in the history of the trap, modifications may have been made that were inappropriate for the proper performance of the pigging system. These are all reasons for performing an assessment on a pig trap or pigging system.

The time it takes to perform a trap assessment depends on the level or levels of assessment required, the experience of the trap assessment team, the working conditions where the trap is located, the remoteness of the trap to be assessed (onshore and offshore) and the operational circumstances of the pipeline section at the time of assessment.

There is a difference between trap assessments and piggability assessments. A trap assessment is an evaluation on the piece of pipeline equipment used for introducing or retrieving a pipeline tool from the pipeline without interruption of pipeline flow. This assessment deals with the evaluation of an existing piece of pigging equipment or pigging system used for launching and receiving pigs or pipeline tools. In contrast, a piggability assessment is an evaluation of an existing pipeline for the purpose of determining the necessary modifications in order to make a pipeline section capable of safely launching, running and receiving pipeline tools.

Levels Of Trap AssessmentA trap assessment can range in complexity and sophistication. There are many levels of trap assessments that can be conducted. Let us look at a description of each level of trap assessment. It may be noted that each level of assessment increases in complexity.

The first level – or Level 1 – trap assessment is called a Research Assessment. This level of assessment explores the history and design parameters of the pig trap. It notes any modifications that have been made to the pig trap from the time of installation to the present, mechanical design limitations of the pig trap, the physical location or designation of the trap or pipeline section, trap dimensions, the location and use of each nozzle on the pig trap.

The Level 2 trap assessment is called an Operational Assessment. This level of assessment is concerned with the current-day operational condition of the pig trap and aspects of the overall pigging system. This assessment observes whether the closure opens, closes or seals properly, whether the pressure warning device on the closure operates correctly, whether the various valves on the pigging system seal adequately, whether the pig signal and pressure gauge work as they should and whether the kicker or bypass nozzles are sized properly.

The Level 3 trap assessment is called the Functionality Assessment. This level of trap assessment determines if the pigging system is performing to its peak effectiveness. If it is desirable to launch or receive inspection tools, is the trap or the surrounding area dimensionally capable of handling this operation? Are there physical obstructions (handrails, stairs, piping, etc.) that make it difficult to safely load or unload pigs? Are piping modifications needed to allow for inspection pigging? Should an equalization line be added across the trap reducer for safety or to improve pigging operations? Should additional vent and pressure gauge nozzles be added to the line size pipe for safety? Should additional drain nozzles be added to the pig trap? These are all questions that this level of trap assessment seeks to answer.

The Level 4 trap assessment is called the Corrosion Assessment. This level of assessment is the most complex and typically will require an NDE technician or engineer to be on the trap assessment team. This evaluation seeks to determine the existence of corrosion agents acting on the components of the pig trap and whether or not these corrosion agents have affected the structural integrity of the carbon steel enough to cause the trap to be unsafe to operate. Are liquid or debris samples being taken? If so, are the samples analyzed for corrosion agents? Are there sampling ports for obtaining liquid or debris samples on the pigging system? Have any inhibitors or biocides been applied to this pipeline section? If so, what was the name of the inhibitor or biocide used and what was the interval of application? Did the inhibitor or biocide have a positive effect or not? Have in-line inspections been conducted on this pipeline section? Has any form of NDE been conducted on the trap since it was installed? If so, has the data been analyzed to assess minimum pipe wall thicknesses? Is NDE performed regularly on the traps to monitor corrosion growth rates? If previous NDE data is provided, corrosion growth rates can be used to estimate the time when repair or replacement of the trap would be necessary.

Trap Assessment Team
A Trap Assessment Team should be composed of the following members at a minimum:

(1) Team Leader/Project Manager – this member is responsible for the assessment team in the field and ensures that the necessary data is collected for the technical writer to create the assessment report.
(2) Project Engineer – this member is the technical expert on the design and operations of pig traps and pigging systems. This member can assume the role of Team Leader/Project Manager for economy of workforce.
(3) Technical Writer – this member assembles the data collected into a technical report which explains to the client the findings of the assessment.
(4) NDE Technician (optional member, for Level 4 Assessments only) – this member performs the non-destructive examination on the trap and provides the data to the Project Engineer for mechanical integrity evaluation.

Assessment Procedure
1. Assemble as much information about the trap and pipeline section as possible before conducting the on-site assessment. Note the history of the trap, pipeline/trap design parameters, location, etc.

2. Onsite Assessment. a) Compare the existing trap with the as-built drawings. If there are any differences, note and sketch them. b) If an as-built drawing is not available, make a sketch of the trap with dimensions. Note nozzle sizes and use. Also note valve types, makes and condition in the pigging system. c) Question the operators and pigging crews about the pigging type, frequency and the operational condition of the different parts of the pigging system. d) Take pictures of the trap. Care should be taken to capture any areas of concern on the trap or pigging system. It has been said that a picture is worth a thousand words. These pictures will be useful as illustrations within the Assessment Report. e) If possible, look inside the trap and note the condition of the inside pipe wall and closure door. f) If a Level 4 Assessment is conducted, the NDE technician should take ultrasonic test readings and record them for further evaluation. g) Assemble the data in an organized fashion and transmit the data to the technical writer.

3. Write the Assessment Report and submit it to the client.

Conclusion
Pig trap development has occurred over many years and will continue as long as there remains the need to pig a pipeline. An understanding of the components, the function of each component and certain performance enhancing and safety features for a launcher and receiver helps one to grasp the function of the overall pigging system and procedures for launching and receiving a pig.

Design considerations should extend beyond the limits of the pig trap to the boundaries of the pigging station. Trap assessments are extremely valuable to the responsible pipeline operator that is concerned with the condition of the pipeline equipment and the safety of the pigging crews in the field.

Sumber: http://pgjonline.com/2011/01/05/pig-trap-design-and-assessment-considerations/

Hydrotest on Offshore Pipeline

Pipeline Hydro Test Pressure Determination

October 2009 Vol. 236 No. 10

Hydrostatic testing has long been used to determine and verify pipeline integrity. Several types of information can be obtained through this verification process.

However, it is essential to identify the limits of the test process and obtainable results. There are several types of flaws that can be detected by hydrostatic testing, such as:

• Existing flaws in the material,
• Stress Corrosion Cracking (SCC) and actual mechanical properties of the pipe,
• Active corrosion cells, and
• Localized hard spots that may cause failure in the presence of hydrogen.

There are some other flaws that cannot be detected by hydrostatic testing. For example, the sub-critical material flaws cannot be detected by hydro testing, but the test has profound impact on the post test behavior of these flaws.

Given that the test will play a significant role in the nondestructive evaluation of pipeline, it is important to determine the correct test pressure and then utilize that test pressure judiciously, to get the desired results.

When a pipeline is designed to operate at a certain maximum operating pressure (MOP), it must be tested to ensure that it is structurally sound and can withstand the internal pressure before being put into service. Generally, gas pipelines are hydrotested by filling the test section of pipe with water and pumping the pressure up to a value that is higher than maximum allowable operating pressure (MAOP) and holding the pressure for a period of four to eight hours.

ASME B 31.8 specifies the test pressure factors for pipelines operating at hoop stress of ? 30% of SMYS. This code also limits the maximum hoop stress permitted during tests for various class locations if the test medium is air or gas. There are different factors associated with different pipeline class and division locations. For example, the hydrotest pressure for a class 3 or 4 location is 1.4 times the MOP. The magnitude of test pressure for class 1 division 1 gas pipeline transportation is usually limited to 125% of the design pressure, if the design pressure is known. The allowed stress in the pipe material is limited to 72% of SMYS. In some cases it is extended to 80% of SMYS. The position of Pipeline and Hazardous Material Safety Administration (PHMSA) is similar. Thus, a pipeline designed to operate continuously at 1,000 psig will be hydrostatically tested to a minimum pressure of 1,250 psig.

Based on the above information, let us consider API 5L X70 pipeline of 32-inch NPS, that has a 0.500-inch wall thickness. Using a temperature de-rating factor of 1.00, we calculate the MOP of this pipeline from following:

P= {2x t x SMYS x1x factor (class1) x 1} / D (ASME B 31.8 Section, 841.11)

Substituting the values:

P= 2x 0.5 x 70,000 x1 x0.72 x1/32 = 1,575 psig

For the same pipeline, if designed to a factor of 0.8, the MOP will be computed to be 1750 psig.

• If the fittings were the limiting factors of the test pressure, then the following situation would arise.
• If the fittings used in the system are of ANSI 600 then the maximum test pressure will be (1.25 x 1,440) 1,800 psig. This test pressure will support the requirements of both factor 0.72 and 0.8.
• If, however, ANSI 900 fittings were chosen for the same pipeline system, the test pressure (1.25 x 2,220) 2,775 psig would test the pipeline but would not test the fittings to their full potential.

Let us first discuss the design factor of 0.72 (class1). In this case the test would result in the hoop reaching to 72% of the SMYS of the pipe material. Testing at 125% of MOP will result in the stress in the pipe reaching a value of 1.25 x 0.72 = 0.90 or 90% of SMYS. Thus, by hydrotesting the pipe at 1.25 times the operating pressure, we are stressing the pipe material to 90% of its yield strength that is 50,400 psi (factor 0.72).

However, if we use a design factor of 0.8 – as is now often used – testing at 125% of MOP will result in the stress in the pipe to 1.25 x 0.8 =1. The stress would reach 100% of the yield strength (SMYS). So, at the test pressure of 1800 psig the stress will be 56,000 psi (for factor 0.8). This will be acceptable in case of class 600 fittings. But, if class 900 fittings were taken into account, the maximum test pressure would be (1.25 x 2,220) 2,775 psig and the resulting stress would be 88,800 psi which will be very near the maximum yield stress (90,000 psi) of API 5L X 70 PSL-2 material.

Test Pressure And Materials SMYS
Though codes and regulatory directives are specific about setting test pressure to below 72% or in some cases up to 80% of the SMYS of the material, there is a strong argument on testing a constructed pipeline to “above 100% of SMYS,” and as high as 120% of SMYS is also mentioned. Such views are often driven by the desire to reduce the number of hydrotest sections, which translates in reduction in cost of construction. In this context, it is often noted that there is some confusion even among experienced engineers on the use of term SMYS and MOP/MAOP in reference to the hydrotest pressure.

It may be pointed out that the stress in material (test pressure) is limited by the SMYS. This is the law of physics, and is not to be broken for monetary gains at the peril of pipeline failure either immediate or in the future.

In this regard, section 32 of directive No. 66 of the Alberta Energy and Utilities Board in 2005 is of importance. The guidance is specific about the situation. It directs that if the test pressure causes hoop stress in the material exceeding 100% of the material SMYS, then the calculation and the entire hydro test procedure needs to be submitted to the board for review and approval.

Stress Relieving And Strength
Often there is argument presented that higher test pressures exceeding 100% of the SMYS will increase the “strength” of the material and will “stress relieve” the material. Both arguments have no technical basis to the point they are made. We will briefly discuss both these arguments here:

1. Higher test pressure will “increase the strength.” As the material is stressed beyond its yield point, the material is in plastic deformation stage, which is a ductile stage, and hence it is in the constant process of losing its ability to withstand any further stress. So, it is not increasing in strength but progressively losing its strength.

2. The second argument of “stress reliving” is linked with the “increase the strength” argument. The stress relief of material is carried out to reduce the locked-in stresses. The process reorients the grains disturbed often by cold working or welding. The stress relief process effectively reduces the yield strength. Thus, it does not “strengthen” the material. Note: It may be pointed out that a limited relaxation of stresses does occur by hydro testing, but the test pressure should be less than the material’s yield point.

Another point to note here is that there is a stage in the stressing of the material where strain hardening occurs and the material certainly gains some (relative) hardness, and thereby, strength. This happens as necking begins but, at that point, unit area stress is so low that the strength of the material is lost and it remains of no practical use, especially in context with the pipe material we are discussing.

Returning to the subject of pressure testing and its objectives. One of the key objectives of the testing is to find the possible flaws in the constructed pipeline. The test develops a certain amount of stress for a given time to allow these possible flaws to open out as leakages. In the following section we shall discuss the relation of these flaws to the test pressure and duration.

Critical Flaw Size
The maximum test pressure should be so designed that it provides a sufficient gap between itself and the operating pressure. In other worlds, the maximum test pressure should be > MOP.

This also presupposes that after the test the surviving flaws in the pipeline shall not grow when the line is placed in service at the maintained operating pressure. For setting the maximum test pressure, it is important to know the effect of pressure on defect growth during the testing on the one hand and on the other flaws whose growth will be affected by pressure over the time.

The defects that would not fail during a one-time, high test pressure are often referred as sub-critical defects. However these sub-critical defects would fail at lower pressure if held for longer time. But the size of discontinuity that would be in the sub-critical group would fail-independent of time-at about 105% of the “hold” pressure. This implies that maximum test pressure would have to be set at 5-10% above the maximum operating pressure (MOP) in order to find such defects during the test and also to avoid growth of sub-critical discontinuities after the hydro test pressure is released and during the operation life of pipeline. This is should be the main objective of the hydro test.

If test pressure reaching 100% (design factor of 0.80) of the SMYS is considered, then one must also consider some important pre conditions attached to the procurement of the steel and pipe. Especially important to consider is the level of flaw size that was accepted in the plate/coil used to manufacture the pipe. The test pressure of such magnitude would require that the acceptable defect size be re-assessed. This is because all else being equal, a higher design factor, resulting in a thinner wall, will lead to a reduction in the critical dimensions of both surface and through-wall defects.

Where such conditions are likely it may be prudent to reconsider the level of accepted flaws in the material. The current recommendations in API 5L 44th edition for acceptance level B2 as per ISO 12094 (for SAW pipes) may not be acceptable because it has limited coverage of body and edges and the acceptance criteria is far too liberal, in terms of acceptable size and area of flaws. More stringent criteria must be specified more in line with EN 10160 where level S2 for body and level E2 for edges may be more appropriate to meet the demands of the higher test pressures.

Sub-critical surface flaw sizes at design factors of 0.80 and 0.72 are susceptible to growth at low stress and are time dependent. These flaws are also dependent on the acceptable limits of impact absorbing energy of the material and weld (not part of the discussion in this article).

This increase in depth-to-thickness (d/t) ratio in effect reduces the ligament of the adjoining defects that reduce the required stress to propagate the discontinuity. Critical through-wall flaw lengths are also factors to be assessed. While there is a modest reduction in critical flaw length, it still indicates very acceptable flaw tolerance for any practical depth and the reduction will have negligible influence in the context of integrity management. Note that flaws deeper than about 70% of wall thickness will fail as stable leaks in both cases. This statement implies that mere radiography of the pipe welds (both field and mill welds) may not suffice. Automatic ultrasonic testing (AUT) of the welds will be better suited to properly determine the size of the planer defects in the welds. Similarly the use of AUT for assessing the flaws in the pipe body will be more stringent than usual.

Pressure Reversal
The phenomenon of pressure reversal occurs when a defect survives a higher hydrostatic test pressure but fails at a lower pressure in a subsequent repressurization. One of the several factors that work to bring on this phenomenon is the creep-like growth of sub-critical discontinuities over time and at lower pressure. The reduction in the wall thickness, caused by corrosion, external damages, is also responsible for a reduction in puncture resistance in the pipe. The reduction in the wall thickness, in effect reduces the discontinuity depth to the material thickness.

This increase in d/t ratio reduces the ligament between the adjoining defects. This effectively reduces the stress required to propagate the discontinuity. The other factor affecting the pressure reversal is the damage to the Crack Tip Opening (CTO). The CTO is subject to some compressive force leading the crack tip to force-close during the initial test. On subsequent pressurization to significantly lower pressure this “force-close” tip starts to open-up and facilitates the growth of the crack. Hence, if such a pressure cycle is part of the design, then the point of pressure reversal should be considered.

Puncture Resistance

• It may also be noted that there is a modest reduction in puncture resistance with both increasing SMYS and increasing design factor. Note that the maximum design factor is, in some instances, constrained by practical limits on D/t.
• In any event, it should be noted that only a small proportion of large excavators are capable of generating a puncture force exceeding 300 kN and that the reductions in puncture resistance noted would have to be assessed for the integrated approaches to the management of mechanical damage threats.

Sumber: http://pgjonline.com/2009/12/17/pipeline-hydro-test-pressure-determination/