Wednesday, January 25, 2023

ASME Pressure vessel/ Heat Exchanger Hydrostatic test - for Internal Pressure

ASME Pressure vessel/ Heat Exchanger Hydrostatic test - for Internal Pressure

ASME Pressure vessel/ Heat Exchanger Hydrostatic test - for Internal Pressure

ASME Section VIII Division 1, UG-99 specifies the hydrostatic test conditions for pressure vessels and heat exchangers.

 


Maximum Hydrostatic Test Pressure

An upper limit for the test pressure is not mentioned in ASME Section VIII Div 1. But it says that ASME authorized inspector has the right to reject the vessel if there is any visible permanent deformation. (UG 99(d)). To be on safer side, many industries try to limit the stress due to hydro test pressure less than 90% of the yield stress.

Minimum Hydrostatic Test Pressure

Option 1

ASME Section VIII Div 1, UG-99 (b)

Minimum Hydrostatic Test Pressure = 1.3 X MAWP x LSR

MAWP is Maximum allowable working pressure. It is always equal to or more than the design pressure. For example, you need just 5mm wall thickness for withstanding the design pressure of 10bar, and the vessel is actually made with a wall thickness of 8mm, the MAWP is more than 10bar. It may be 15bar for instance. Nevertheless, the design engineer has the right to write the MAWP as any number above design pressure and below the actual MAWP (15bar here) on name plate and U1 form. He can even say the MAWP= Design pressure, which is 10bar. The end note 36 marked in the paragraph (UG-99b) allows the MAWP to be equated to design pressure.

LSR is lowest stress ratio. It is a conversion factor used to convert the ASME material stress value at the test temperature to the Stress value at the design temperature. It is a kind of temperature correction factor. The purpose of the hydrostatic test is to simulate the real design stress on the vessel walls. So, this is the only way practically possible in a shop.

Option 2

Another method to find out the minimum test pressure is using the MAP, Maximum Allowable Pressure at test temperature.

UG-99(c)

Minimum test pressure= (1.3 X MAP) – Hydro static head

This method is less popular compared to UG-99(b)

Test temperature

The Code recommends that the metal temperature during hydrostatic test be maintained at least 30°F (17°C) above the minimum design metal temperature, but need not exceed 120°F (48°C), to minimize the risk of brittle fracture.

Minimum Hold time

ASME section VIII don't say anything about the test pressure hold time. Normally it is determined by the quality procedure of the shop or by ASME authorized inspector. 30 minutes to 60 minutes is generally followed. When it comes to Shell and Tube heat exchangers, TEMA (Tubular exchanger Manufactures Association) specifies minimum test duration as 30 minutes.



53A, 53B, 53C - Pressurized Dual Mechanical Seal Plans

53A, 53B, 53C - Pressurized Dual Mechanical Seal Plans

Pressurized Dual Mechanical Seal Plans (53A, 53B, 53C)


In the past there was only one Plan 53, but with the 2nd Edition of API 682 and the 1st Edition of ISO 21049 other variations of Plan 53's were created.

Plan 53A is the former Plan 53. Plan 53B is what had been in the past denoted as Plan 53 Modified; this is especially popular in European and other countries in the Middle East. Plan 53C is a variation of this that has also been used in the past and is now formally recognized.

The major difference in the plans is that Plan 53A uses an external reservoir, while Plans 53B and 53C run within a closed loop system with a make-up system piped to it for replenishment of the barrier fluid.

In dual pressurized sealing arrangements the inner process seal can have its own flush plan; in such applications the complete flush plan system designation should include both plans. For example, Plan 11/53A means that the inner seal has its own flush plan, Plan 11. The API/ISO default is for no separate flush plan when using any of the Plan 53's, but this can vary with the application conditions.

With the older traditional back-to-back seal arrangement the inboard seal usually does not require a separate flush. In applications such a hydrofluoric acid, where it is both extremely hazardous and corrosive, a Plan 32 can be used in conjunction with a Plan 53. The dual pressurized face-to-back seal arrangement eliminates some of the potential problems associated with the back-to-back design. This face-to-back seal arrangement sometimes incorporates a reverse pressure capability that is not a default with the back-to-back design.

Also, face-to-back arrangements do not have a dead zone underneath the inboard seal that can become clogged by dirty process fluid and lead to seal hang-up. However, the face-to-back arrangement is not a cure-all. With the product on the seal O.D. and with it being used on API pumps that still incorporate throat bushings, it is advantageous to provide a flush for the inboard seal on a number of applications.

Abrasives can accumulate in the more closed API type seal chambers compared to the newer generation chemical duty pumps with large cylindrical bore or tapered bore chambers. The use of a Plan 11 or similar bypass type flush for the inner seal has advantages. It can help keep the seal chamber clean. It also has an improved overall heat transfer setup versus just using a Plan 53 system alone.

In comparison to a Plan 54, Plans 53A/B/C are usually less complex and less expensive. With Plans 53A/B/C, both the inner and the outer seals are lubricated by the barrier fluid, which can be selected for optimum seal performance. Plans 53A/B/C are usually selected for dirty, abrasive, or polymerizing process services which might be difficult to seal directly with single seals or with dual unpressurized seals using a Plan 52. There will always be some leakage of the barrier fluid into the process with any pressurized system.

With some of the Plan 53 systems the volume of barrier fluid is limited, especially compared to a Plan 54 system. Venting of the seal chamber is essential for all Plan 53's where vapor locking can if vapor bubbles collect near the pumping ring or in the piping.

Plan 53A

Plan 53A uses an external reservoir to provide barrier fluid for a pressurized dual seal arrangement. Reservoir pressure is produced by a gas, usually nitrogen, at a pressure greater than the maximum process pressure being sealed. The gas pressure is regulated by a system that is outside the schematic of the piping plan. Circulation of the barrier fluid is maintained by an internal pumping ring.

Like Plan 52 reservoirs, cooling is accomplished internal coil of tubing to remove the heat. Also like Plan 52 reservoirs, the volume of barrier liquid can vary from two gallons to 5+ gallons, where API and ISO standards specify 3-gal and 5-gal, depending upon the shaft diameter.

For non-API specifications, smaller reservoirs - typically 2-gal - are often used, especially at ambient pumping temperatures. Pressure alarms, pressure gages and level switches are typically standard equipment and are required by API 682/ISO 21049.

The usual guideline for Plan 53 barrier pressures is that they be a minimum of 20-psi to 50-psi above the maximum process pressure seen by the seal. Barrier pressure is normally supplied by a plant wide distribution system. Nitrogen bottles should not be used as they require a lot of attention and maintenance.

API 682/ISO 21049 recommends that the system be limited to 150-psig due to gas entrainment into the barrier fluid. Field experience has shown that with the proper barrier fluid, Plan 53A systems can be used up to 300-psig if the temperature is controlled to less than 250-deg F. A variation to this would be to use an accumulator to eliminate gas entrainment.

Advantages (vs. other Plan 53 systems)

Least expensive of the various Plan 53 systems.

Should the loop be contaminated for any reason, the contamination is isolated to a single installation.

Wear particles that are heavier than the barrier fluid will settle to the bottom of the reservoir away from the reservoir outlet to the seal chamber.

The volume of barrier fluid is dependent upon the size of the reservoir. Larger flow rates should use larger reservoir sizes so that retention time in the reservoir is maximized for longer fluid life.

Disadvantages (vs. other Plan 53 systems)

The barrier fluid in Plan 53A is subject to gas entrainment due to direct exposure to the pressurizing gas. Different barrier fluids have varying levels of gas entrainment.

Heat dissipation capacity is limited to the coiling coils unlike Plan 53B/C, which have separate and potentially larger capacity.

Installation should be limited to a single seal installation even on between bearing pumps. Therefore for a large number of installations, Plan 53A can be more expensive than Plan 53B or 53C.

 

Plan 53B

nlike a Plan 53A that incorporates a pressurized reservoir within the circulation loop, Plan 53B incorporates a bladder type accumulator along with the piping and an air or water cooled heat exchanger to provide for barrier fluid capacity.

Some installations use finned tubing as the heat exchanger, but these should be used with caution as the heat removal depends upon a positive air flow across the tubing to be effective. Gas entrainment is not a problem with this plan since it incorporates bladder accumulator to maintain the barrier pressure within the closed loop circuit.

The accumulator should be pre-pressurized to between 80 percent and 90 percent of the barrier pressure. This creates a problem in that it limits the volume of fluid within the Plan 53B circuit. The majority of the accumulator volume is gas. The basic setup is comprised of two parts; the closed loop circulating system made up of the piping and heat exchanger and the make up system.

Flow in the circulating system is usually induced by an internal pumping device. The make up system can be configured a number of ways based upon the customer's preference, ranging from a simple hand pump to an elaborate pumping system feeding multiple pumps/seals.

Like Plan 53A, the flow rate of the Plan 53B circuit is controlled by the pumping ring design, peripheral speed, barrier fluid viscosity, and resistance of the piping circuit; the piping circuit of 53B includes a heat exchanger. The sizing of the heat exchanger depends upon the heat load of the system. The heat exchanger should be designed to contribute minimum resistance.

API 682, 3rd edition does not provide guidelines for sizing the accumulator of Plan 53B, but the total fluid volume of the system should be about the same as the volume of a 53A system.

Advantages (vs. other Plan 53 systems)

The contamination within the loop if any is contained within the closed circuit.

The make up system can supply pressurized barrier fluid to multiple dual pressurized sealing systems with either like or unlike pressure conditions.

The barrier fluid is not subject to nitrogen or air entrainment as with a Plan 53A.

Disadvantages (vs. other Plan 53 systems)

The volume of fluid within the closed loop circuit is very limited, as little as one-half gallon in some instances.

With the limited fluid volume the barrier fluid gets thermally cycled on a much more frequent basis than a Plan 53A, so the service life of the fluid is reduced.

The finite volume of the accumulator requires a designed pressure operating range between refills (in excess of that required for a Plan 53A) and this must be built into the pressure rating of the seals.

A change in the system temperature affects the Plan 53B pressure.

The separate heat exchanger introduces additional flow resistance to the piping system and will have a lower flow rate than an otherwise identical Plan 53A.

Wear debris has nowhere to settle as in a Plan 53A system so it is continually circulated.

Plan 53C

Plan 53C is a variation of Plan 53B that uses a piston accumulator to track the pressure of the seal chamber. In Plan 53C, the piston accumulator has a reference line from the seal chamber to the bottom of the accumulator. There are differences in diameter of the internal piston so that a higher pressure is generated on the top half, which in turn is piped to the circuit loop into and out of the seal chamber.

Similar to Plan 53B, there is no gas pressurizing the barrier fluid so there is no chance of gas entrainment. Also, like Plan 53B flow is generated by a pumping ring through a heat exchanger. The heat exchanger can be water cooled, air cooled or can be finned tubing if the heat load is small enough. This system should be used with caution, as the reference line to the accumulator is subject to the process fluid. The process fluid may be corrosive, abrasive, or a slurry that could potentially clog the pressure reference line threatening the tracking ability of the system.

Advantages & Disadvantages (vs. other Plan 53 systems)

The advantages and disadvantages are the same as the Plan 53B system. Additionally, the disadvantage of this system is that pressure spikes or pressure drops in the process pressure will vary the pressure on the outer seal that may create a temporary leakage condition. Also, tracking pressures can always be subject to delays that can cause a temporary loss of positive pressure differential across the inboard seal.

References:

By Gordon Buck and Ralph Gabriel, John Crane Inc.December 17, 2011

Common Causes of Flange Leakage & Benefits of Immediate Leak Detection

Common Causes of Flange Leakage & Benefits of Immediate Leak Detection

Common Causes of Flange Leakage & Benefits of Immediate Leak Detection

A previous article highlighted the primary causes of flange leakage. In this article I provide more information about these flange leak cause :

Uneven Bolt Stress. An incorrect boltup procedure or cramped working conditions near the flange can leave some bolts loose while others are overtightened and crush the gasket. This can cause in-service leaks, especially in high temperature services when the heavily loaded bolts relax.

Improper Flange Alignment. Improper flange alignment, especially flange face parallelism, causes uneven gasket compression, local crushing, and can cause subsequent leakage. Improper flange centerline alignment can also cause uneven gasket compression and flange leaks.

Improper Gasket Centering. If a gasket is installed off center compared to the flange faces, the gasket will be unevenly compressed and make the joint prone to leakage. Spiral wound and double jacketed gaskets usually have a centering ring that extends to the inner edge of the bolts. A sheet gasket can be cut so that its outside diameter matches the inner edge of the bolts.

Dirty or Damaged Flange Faces. Dirt, scale, scratches, protrusions, weld spatter on gasket seating surfaces, and warped seating surfaces provide leakage paths or can cause uneven gasket compression that can result in flange leakage.

Excessive Piping System Loads at Flange Locations. Excessive forces and bending moments can loosen the bolting or distort the flanges and lead to leaks. Common causes are inadequate piping flexibility, using cold spring to align flanges, and improper location of supports or restraints.

Thermal Shock. Rapid temperature fluctuations can cause flanges to deform temporarily. This is typically a greater potential problem in high temperature applications. Process variations cannot always be avoided. A related problem is temperature variation around the flange circumference (e.g., cooling on top due to rain, or cool liquid at the bottom and hot gas at the top). Where this is a problem, sheet metal shields can be installed to protect against rain or snow impingement that could cause thermal gradients across the flange and cause leakage. Such shields also serve to keep the flanges and bolts at a more uniform temperature.

Improper Gasket Size or Material. Sometimes, the wrong gasket size or material is installed. The wrong size should be fairly obvious during installation, and something that a trained boltup crew will immediately identify. The wrong material may not be apparent until corrosion or blowout damages the gasket.

Improper Flange Facing. Deeper serrations than specified will prevent the seating of double jacketed or spiral wound gaskets and provide a leakage path. Normal raised face flange finishes have grooves that are 0.002 to 0.005 in. (0.05 to 0.13 mm) deep.

High Vibration Levels. Excessive vibration can loosen flange bolts and ultimately cause flange leakage.

So What are the benefits of the Immediate Leak Detection?

When the Leak Detection and Repair requirements were developed, it is estimated that petroleum refineries could reduce emissions from equipment leaks by 63% by implementing a facility Leak Detection and Repair program. Additionally, it is estimated that chemical facilities could reduce VOC emissions by 56% by implementing such a program.

 

Emissions reductions from implementing an Leak Detection and Repair program potentially reduce product losses, increase safety for workers and operators, decrease exposure of the surrounding community, reduce emissions fees, and help facilities avoid enforcement actions.

 

1.     Reducing Product Losses

In the petrochemical industry, saleable products are lost whenever emissions escape from process equipment. Lost product generally translates into lost revenue.

2.     Increasing Safety for Facility Workers and Operators

Many of the compounds emitted from refineries and chemical facilities may pose a hazard to exposed workers and operators. Reducing emissions from leaking equipment has the direct benefit of reducing occupational exposure to hazardous compounds.

3.     Decreasing Exposure for the Surrounding Community

In addition to workers and operators at a facility, the population of a surrounding community can be affected by severe, long-term exposure to toxic air pollutants as a result of leaking equipment. Although most of the community exposure may be episodic, chronic health effects can result from long-term exposure to emissions from leaking equipment that is either not identified as leaking or not repaired.

4.     Potentially Reducing Emission Fees

To fund permitting programs, some states and local air pollution districts charge annual fees that are based on total facility emissions. A facility with an effective program for reducing leaking equipment can potentially decrease the amount of these annual fees.

 

5.     Avoiding Enforcement Actions

In setting Compliance and Enforcement National Priorities for Air Toxics, U.S Environmental Protection Agency has identified Leak Detection programs as a national focus. Therefore, facilities can expect an increased number and frequency of compliance inspections and a closer review of compliance reports submitted to permitting authorities in an effort by the Agency to assess Leak Detection programs and identify potential Leak problems. A facility with an effective Leak Detection program decreases the chances of being targeted for enforcement actions and avoids the costs and penalties associated with rule violations

How can we differentiate a Piping Layout, Plant layout, Plot Plan and General Arrangement drawing (GA)

How can we differentiate a Piping Layout, Plant layout, Plot Plan and General Arrangement drawing (GA)

How can we differentiate a Piping Layout, Plant layout, Plot Plan and General Arrangement drawing (GA)

First, some of these terms are "work activities" (or "a work process") and some are the "deliverables" (or the "product") of a work activity. Lets start by putting them in the order we would normally see accomplish them.

Plant layout: This is first a "work activity." It is the process of determining what Area you have for a Plant, the equipment or units you need to fit into the Area and the exact relationship these items must have relative to each other. In the past it has been done with manual sketches, paper cut-outs and small scale block models. Today it can be done in "Model Space" by moving around circles, rectangles and squares, as long as you keep it simple. Remember, this is an activity, it is not a deliverable. You can call it the Plant Layout, but it is still not the deliverable.

Plot Plan: (aka: General Arrangement drawing or GA): This is a "deliverable." After the overall plant layout or unit layout has reached a point where the actual equipment number, sizes and shapes are known the "Model Space" version of the plant layout can be up-dated and formalized. It would then be moved to "Paper Space", a Title Block added and the formal Plot Plan produced. This document now goes to various people for review and approval including the Client. Because of the timing, the scale and the purpose of this Plot Plan document it would not and should not have any coordinates or dimensions on it to locate equipment or facilities.

Location Control Plan (LCP): This document is a limited internal deliverable tool that would not and should not be issued to the job site. This is the more detailed step to fixing the location of each piece of equipment in to its final location. This final location will be based on the purpose, function size of that piece of equipment along with the piping layout, operation space and the maintenance space. In addition to this there are the space requirements for any related electrical equipment and instrumentation requirements. The final location of each piece of equipment is also affected by the foundation design, and the foundation design is impacted by the type and stability of the soil at the site. The final location of a piece of equipment should only be conveyed to the field by the document (maybe called Foundation Location Plan) from the Structural department.

Piping Layout: This is first an activity (or a process) and then a product. A piping designer does piping layout. This is the process of defining the piece of equipment, the maintenance spaces and the related electrical needs. Then routes the piping to accomplish the process function of the piece of equipment then add the space requirements for operation and you have a piping layout. The final location of any piece of equipment is impacted by the piping layout. This final location is added to the "GA" (or LCP) which is then routed to the structural group. As you can see there is a normal understood cycle and recycle between the piping group with the piping layouts, the "GA's" and the structural group and their "Foundation Location Plan".

Piping Plans (& Sections): These are the most detailed drawings created by the Piping Engineering and Design effort. They may be created via 2D CAD or be extracted from a 3D model. The level of detail is very specific. The equipment is shown in rough outline but with Equipment Number, key centerline coordinates all the nozzles. The nozzles are all shown in detail and in exact location and identification. Piping is also shown in detail with enough information to draw or check Isometrics.
ASME Flange Ratings and Flange Classes

ASME Flange Ratings and Flange Classes

ASME Flange Ratings and Flange Classes


Flanges are a pipe fitting whose function is to join two pieces in a piping system, and easily separate them at a particular time, allowing to be disassembled without destructive operations. By function and utility, the flanges are present in many sectors and areas such as construction and industry and a lot of application in oil and gas sector .

 It's possible to produce standard flanges as ASA/ANSI/ASME (USA), PN/DIN (European), BS10 (British/Australian), and JIS/KS (Japanese/Korean). And usually these standards are not interchangeable. I have tried to simplify some of the terms as used by ASME and ANSI for a better understanding .

Definition of Pressure-Temperature Rating

Pressure- temperature rating is the maximum allowable non-shock gauge pressure at the specific temperature for a given material as covered in ASME B16. for Pipe Flanges and Flanged Fittings that covers flanges sizes from NPS ½" to 24".

What is Temperature Rating?

The ability of a material to handle the stresses at a given temperature as detailed in ASME B31.3 . It is worth noting that different material can handle different amounts of stress at different temperatures.

What is Pressure Rating?

The pressure rating is safe working or maximum operating pressure with respect to the working temperature. It depends on the materials' Stress-Strain characteristics. It is available in different Codes and Standards.

What is Flange Class?

Many of the flanges in each standard are divided into "pressure classes", depending on the different rates of pressure that are able to endure. The most common flanges pressure classes are #150, #300, #600, #900, #1500, #2500 and #3000 according to ASME designation. To other standards, as DIN, pressure classes are defined by the acronym PN, as for example, PN10, PN16, PN20, PN25, PN40, PN50, PN100, PN150, PN250 or PN420. Flanges from different pressure classes are not usually interchangeable.  


A pipe flange connects piping and components in a piping system by use of bolted connections and gaskets


Some Important Piping Codes and Standards for Saudi Aramco

Some Important Piping Codes and Standards for Saudi Aramco

Some Important Piping Codes and Standards for Saudi Aramco Related Works


Codes and standards both provide the engineering criteria or method through which the piping integrity can be ensured and it simplifies the design consideration to make sure adherence to the standards. Piping codes and standards are the main pillars of any piping industry. As, the integrity of the piping system depends upon the considerations and principles used for designing, construction, inspection, and maintenance of the system. In practice, the assurance that the design and construction of a piping system will meet safety requirements is achieved through the use of published engineering codes and standards.

SAES (Saudi Aramco Engineering Standards) series for design, construction and inspection of piping systems are owned or operated by Saudi Aramco and are implemented strictly without compromise to ensure safety and most highly regarded best practices as covered in SABP. These standards set the rules and basis for selecting the applicable Saudi Aramco engineering standards or materials and documentation. For the most part, SAES supplements in some way ASME B31 ,API and ASTM .

For pipeline and piping standards, Saudi Aramco established the following SAES ;

SAES-A-004 – General requirements for pressure testing of a new and existing pipelines ( ASME B31's, API and other applicable codes.)

SAES-L-100 – Applicable codes and standards for pressure piping system. (ASME B31.1, B31.3, B31.4 and ASME B31.8)

SAES- L-136 Pipe election and Restrictions

SAES-L-450– Construction of On-land and Near Shore Pipeline ( ASME B31.4 and B31.8 transportation piping code)

SAES-L-310 Design of Plant Piping

SAES-L-410 Design of Pipelines

SAES-W-012 Welding requirements for Pipeline

It further goes to adoption of key component of the following ASME B 31 series

Saudi Arabia is the world's largest producer and exporter of oil, and has one quarter of the world's known oil reserves – more than 260 billion barrels

ASME B31.1 Power piping (steam piping etc.)

ASME B31.3 Process piping

 ASME B31.4 Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids

ASME B31.5 Refrigeration piping and heat transfer components

ASME B31.8 Gas transmission and distribution piping systems

ASME B31.9 Building services piping

ASME B31.11 Slurry Transportation Piping Systems (Withdrawn, Superseded by B31.4)

ASME B31.12 Hydrogen Piping and Pipelines

Saudi Aramco also adopts NACE MR0175 for sour service to address metallic surface cracking and exposure to high levels of H2S.


This article does not cover detailed outline and description of the standards; SAES, SAEP, SABP, ISO, ASTM and ASME.

Image Courtesy :ARAMCO facility in Kingdom of Saudi Arabia

Basis of Preparation - Saudi Aramco 2020 Download PDF

Basis of Preparation - Saudi Aramco 2020 Download PDF


About this document:


The tables below provide an overview of the approach and scope used for data consolidation and form the basis

for independent assurance of our sustainability performance data, as published in Saudi Aramco's 2021 Sustainability Report. 

In preparing this document, consideration has been given to following principles: 

      Data Preparation: to highlight to readers of this information the primary principles of relevance and reliability of information; and

      Data Reporting: the primary principles are comparability and consistency with other data including previous years and transparency providing clarity to users.  


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