Things API 610 got wrong part 8

This entry into the joyfully unconstrained "Things API 610 got wrong" series was inspired by the confluence of two things:

Firstly the release of API 610?12th edition (which it should be noted took 10+ years from the previous edition).?Kirit Domadiya has published a nice summary of the changes from 11th to 12th edition?and I'd recommend taking the time to review it.

The second thing was recently observing again (since I've been through this several times), the real world challenges inherent when an industry trend is substituted for sound Engineering practice.

This particular topic has been a trend for multiple years to the point that I should have written about it much sooner than 2023 (my apologies to readers for my continued tardiness). However in my defense I wasn't expecting API 610?12th edition to codify the error.

My goal with this series of posts on?API 610?is to inform , spark debate and occasionally be accused of entertainment. I will be assured that I've accomplished this if you the reader find this installment more entertaining than a?Wombat dance. (Observant readers may note in my blogs that Wombats have a habit of contributing to many hitherto unexplained pump phenomenon. In fact I fully expect that they will eventually have their?own chapter in my favourite pump book?(one that I highly recommend you own).

So with that said let's talk about API 610:

Caveat Lector

Before I continue with part 8 of the topic, I'd just like to recognize what?API 610?got?Right?and the tremendous value of?API 610?in guiding pump manufacturers and purchasers alike into specifying and building safe, reliable products. What I'm writing about in this series are quibbles with what is 99.9% otherwise an excellent standard.

I'd also like to mention the largely unrecognized Engineers who collectively put in many thousands of hours of time and care into crafting the standard.?They are the ones very much deserving of your consideration and praise. A few of them such as Ron Adams, Morg Bruck and Bill Goodman I've been very lucky to work with and have benefited greatly from their wisdom.

What API 610 got Wrong?#8

7.6.1.7 - Codifying the use of a coating (that has been a multi year industry trend), as best practice when in fact the coating has significant performance limitations.

To fully understand the arc of history we need to look at this clause of?API 610?from both the 9th to 11th edition and contrast it with the version currently in 12th edition.

This clause of?API 610?in the 9th through 11th edition states:

7.5.1.7?The bolting requirements of 6.1.30 apply to the connection of auxiliary piping to equipment. Flange fasteners on stainless steel piping systems in lubricating oil need not be stainless steel unless specified. If the purchaser does not specify stainless steel fasteners, they shall be low-alloy steel (e.g. ASTM A193/A193M, Grade B7) and the purchaser shall specify whether they shall be coated (such as by PTFE coating or galvanizing in accordance with ISO 10684 or ASTM A153/A153M) or painted.

Contrast this with clause of?API 610?12th edition which states:

7.6.1.7?The bolting requirements of 6.1.36 apply to the connection of auxiliary piping to equipment. Flange fasteners on stainless steel piping systems for lubricating oil services shall be stainless steel or if specified, low-alloy steel (e.g. ASTM A193/A193M, Grade B7) with polytetrafluroethylene (PTFE) coating or another coating method acceptable to purchaser. Cadmium plated bolting is not acceptable.

The key issue here is the?transition of API 610 12th to allowing (codifying) PTFE fastener coatings by default.

To understand why this is wrong we need to look at a number of historical data points. I've attempted to break these down below

#1 Painting by Numbers

At this point I'm sure a number of you are wondering why you should care about auxiliary piping fasteners (or any other faster on the pump for that matter).

In truth fasteners are critical to the safe and reliable operation of the equipment. Keep in mind that over the equipment's 20+ year life it will receive multiple maintenance sessions (assuming the normal 3 year period of uninterrupted operation applies).

At each one of those maintenance sessions, many fasteners will be removed and then reinstalled. In the case of major overhaul on a large skid package, hundreds of fasteners will be disturbed. It is therefore critical that those fasteners can be removed and replaced in a way that does not significantly affect their reliability or safety function.

In the past it was common to utilize a painted carbon steel fastener. While this provided some measure of protection against corrosion it had several limitations:

1. It is difficult to apply paint to a fastener in a way that ensures even coverage of all of the exposed metal surface.
2. Successful coating of the fastener required removal of grease or other assembly lubricants. This degreasing step is time consuming and messy.
3. The paint systems needed for extreme conditions - such as offshore marine are typically 2 or 3 part systems with very specific surface preparation requirements. Such requirements can't practically be achieved for fasteners resulting in substandard protection.
4. The fastener needs to be repainted after each disassembly/assembly cycle.
5. Any break or weak point in the surface forms an initiating site for corrosion and in some cases may concentrate it.

#2 Sacrificial vs Barrier Coatings

The painting discussed above is an example of a Barrier Coating. These coatings provide corrosion protection by preventing the substrate from being exposed to the corrosion medium (in our case normally oxygen in the air, moisture and the salt in marine environments).

There is an alternative protection mechanism provided by Sacrificial Coatings. These are coatings where the substrate is coated (fully or partially) with a substance that is more reactive to corrosive elements than the substrate.

The most commonly used Sacrificial Coating is galvanizing. Galvanizing is applying a layer of zinc over the substrate (traditionally by dipping it in a bath of molten zinc). Not only does this provide a protective Barrier but additionally the zinc is more electrochemically reactive than the substrate. This means that even if the zinc coating is damaged, it will still corrode in preference to the exposed substrate and hence provide considerable protection to it.

For those of you wanting to understand the above summary in more detail, I'd recommend the following resource as a starting point.

#3 The great Hydrogen Embrittlement panic

This is a key point that was instrumental in driving the current industry direction and hence I need to spend time explaining it.

Hydrogen Embrittlement is the process whereby Hydrogen gets diffused into steel (although other metals can also be susceptible), and in certain conditions results in the the steel cracking and failing in a catastrophic manner. The resource below covers the background in more detail.

The key thing to note here is that galvanizing of steel can result in Hydrogen Embrittlement. After some high-profile failures involving galvanized fasteners many in the Oil & Gas industry concluded that galvanizing fasteners was always a high risk practice and should be avoided.

That was an incorrect conclusion.

What was lost was the understanding that certain conditions need to present for Hydrogen Embrittlement to occur in steel. These are:

1. A steel ultimate tensile strength (UTS) of > 1034 MPa (150 ksi)
2. A steel hardness of > 39 HRC

Since the steel strength and hardness are related, most standards such as ASTM F2329 and ASTM F1941 prohibit the galvanizing and electroplating of fasteners based solely on the hardness criteria.

If we look at the ASTM A193/A193M, Grade B7 fasteners commonly used both for pump casing pressure boundary bolting and for auxiliary piping bolting, the following parameters are relevant:

• B7 material UTS (minimum) to 690 to 862 MPa (100 to 125 ksi)
• B7 material hardness (maximum) 35 HRC

Hence for correctly manufactured B7 fasteners there is no possibility of Hydrogen Embrittlement in normal use*.

For those wanting to delve further into the detail the following resources are recommended

PTFE coatings - Panacea or Not ?

With the limitations of painting of fasteners well known and the over-reaction to the risk of hydrogen embrittlement of galvanized fasteners in place, the question of how to protect fasteners needed a solution.

One possibility is to utilize stainless steel, however this has a number of limitations:

• Most commonly available austenitic fastener grades are low strength compared to their carbon steel counterparts.
• The costs for stainless fasteners are significantly higher.
• The preload characteristics from torquing are generally poor - meaning that the coefficient of friction is high and galling of the fastener is a significant risk.

On paper at least PTFE coated fasteners (there are a number of proprietary brand names), provided benefits:

• The PTFE coating could be applied to the fastener before assembly of the equipment.
• The PTFE coating provided a predictable coefficient of friction and hence torque/preload could be well controlled.
• Lab testing of the PTFE coating to ASTM B117 and G85 show good results for correctly applied coatings.
• You can get the coating in many bright and fun colours (see the picture below).

Because of this I've seen a significant expansion of specifications mandating a PTFE coating for pump and package fasteners. In this context of?API 610?12th edition dropping the option for galvanizing is just a recognition of this.

Here's the problem - in real practice the coatings don't perform acceptably - that is to say don't solve the problem of controlling corrosion on fasteners that will be installed and removed multiple times over the life of the equipment.

Below are examples of PTFE coated studs and nuts that have been assembled and disassembled just once. You can see the crest of the stud threads are bare metal. The inside threads of the nuts fared worse and now have limited coating left intact.

The above is not an anomaly or outlier result.

In the past we always dreaded PTFE being specified for the main pressure boundary studs on pump casings. This was because we knew that these would require several assembly/disassembly cycles as part of the normal manufacturing and testing process.

At the final inspection it would be obvious that the PTFE was damaged and that would be a cause for customer inspector rejection...

So the workaround was to have double the quantity of studs/nuts and use one sacrificial set during assembly/testing then swap in a brand new set only at final preparation for shipment. Obviously the first time the pump was serviced in the field, the coating would be similarly damaged and require additional protection such as field painting to prevent the inevitable corrosion.

Caveat Corrosio

So why did API 610 adopt such a sub optimal solution ? My best guess is industry/peer pressure - coupled with a lack of deep metallurgical understanding. (See also my post What API 610 got wrong part 4 for another example where API 610's metallurgical knowledge was misapplied).

Regardless, it fails to solve a non-existent problem (Hydrogen Embrittlement). As such users of pumping equipment can and should expect better guidance that considers the maintenance realities of their equipment.

Please feel free to express your opinions for or against my critique of PTFE coatings. I always appreciate the feedback.

Until next time Beatus Centrifuga

*There was a reported edge case of suspected Hydrogen Embrittlement in B7 grade fasteners used in a subsea application where both galvanizing and cathodic protection were deployed. The issue seems to have been interaction of the two protection methods.