In this article, we’re going to cover the steps required for electrical pre-commissioning. Prior to on-site pre-commissioning, there are some key off-site activities to take place to ensure that our electrical pre-commissioning goes smoothly. Let’s set our pre-commissioning up for success by reviewing the required off-site activities first.

FAT/IFAT

One of the key activities to take place off-site prior to pre-commissioning is Factory Acceptance Testing (FAT) and particularly Integrated Factory Acceptance Testing (IFAT). This is the testing that’s done off-site in the factory before equipment is shipped to the site, and it’s important to do proper Factory Acceptance Tests so that we can identify any errors with the equipment, or any issues that need to be rectified before the equipment gets to site. Without a properly conducted FAT, then the issues that would have been discovered in the factory are deferred to later in the project and only discovered during on-site commissioning, which of course is going to cause delays with our on-site commissioning activities, particularly when systems have software involved. Integration of both the hardware and the software in the factory needs to be tested before the equipment is shipped to the site.

It’s too late in the project to only be integrating software with the systems on-site after equipment has been installed. At that point, all of the issues that should have been discovered earlier in the factory are transferred to later in the project, making our on-site commissioning so much more difficult. So, we need to ensure that proper integration of the hardware and the software is completed in the factory before equipment ships to site. Now, testing in the factory isn’t a replacement for testing on-site. Both need to be completed because the test setups are somewhat different. Anything that we can test in advance is going to mitigate risk later in the project so that we don’t have issues during on-site pre-commissioning and commissioning.

Construction Completion and Mechanical Completion

Another aspect to focus on is construction completion. Our construction counterparts are going to be installing and assembling the equipment, and there are certain aspects that they’re going to be testing in their Inspection Test Plans (ITPs) prior to handover to commissioning – tests like point-to-point checks to confirm that cables are pulled correctly and terminated correctly into each of the communication cubicles, as well as megger checks to make sure that any of the cables that are installed on-site aren’t damaged or are going to cause any issues during commissioning. This process to confirm construction completion is called Mechanical Completion.

Each Mechanical Completion defines the system to be handed over, the level of QA/QC to be completed on that equipment, and the date when that particular system or subsystem is required to be handed over to the commissioning team so that we can proceed with our electrical pre-commissioning activities. In advance of on-site commissioning from a commissioning team perspective, we’re also getting all our pre-commissioning documentation in place. These would be all the checklists that we’re going to use to verify the various components of the project. We’re going through the drawings, identifying the equipment to test, the level of testing to take place, and putting together all the paperwork and the checklists so that we have those in hand. Once we mobilize to the site to start pre-commissioning, we know exactly what we need to do, and we can start executing per the checklists.

Pre-Commissioning Documentation

There’s a lot of equipment to test, but we don’t necessarily need to go and create all of these checklists from scratch. A lot of these devices have been tested in the past for many years, and the checks are very similar to what’s been done for decades. We need to be leveraging the online databases that exist, that have a lot of these standard checklists. You can get a really good head start by accessing these repositories of checklists online as a great starting point to help us create some of this documentation – at least to use a template to create our pre-commissioning documentation.

Site Acceptance Testing

One of the first terms you might hear during pre-commissioning on-site is Site Acceptance Testing or System Acceptance Testing (SAT). The SAT is the complement to the FAT. What would have been tested in the factory is then tested again on-site, and the results are compared between the two. This is to confirm that since the equipment left the factory, there was no damage during shipping or no damage during installation, that we’re getting the same results from what was measured in the factory. For example, we may be doing a vibration test on a pump or a motor, but we want to confirm that the vibration levels are the same on-site as were measured in the factory. Some tests may be more complex, such as electrical tests related to winding resistance or transformer ratios – we want to make sure that equipment wasn’t damaged or internal components dislodged and are not giving us different results than we measured in the factory.

Often the vendor is involved in SAT to confirm that they’ve completed their scope of work for delivery of the equipment to the site, and it still meets contract requirements and matches what was measured in the factory. The vendor participates because once these tests are passed, this confirms that the vendor has completed testing and equipment can be signed off for payment of the item. At that point, that piece of equipment can then be used for further integration into other systems on-site.

Electrical Pre-Commissioning

Electrical pre-commissioning is performed by the commissioning team. Electrical testing typically involves more complex test setups and often requires specialized test equipment that only the commissioning team would have, or even a specialized team that’s brought in as a member of the commissioning team to perform electrical pre-commissioning.

When we perform open circuit tests or short-circuit tests, these involve large closures into ground and require very specialized monitoring equipment to measure transients during the applied fault. This type of testing requires specialized equipment and a specialized skillset that the commissioning team can bring to the project to complete these specialized tests. Some first checks to be done during electrical pre-commissioning are to confirm that equipment is grounded and bonded correctly to station ground. This is important to do early because as the equipment is being energized for the first time, we can potentially encounter faults with the system. And if that occurs, we want to make sure that everything is grounded correctly and that any transients or faults can be routed into the station ground system rather than through other equipment or through individuals involved. Any bonds of any floating metallic conductors will be verified around the station to confirm that all of the fault paths to the ground are in place prior to energizing any of the equipment.

First Power and Loop Checks

Next, we’ll apply first power to the equipment. This isn’t the main circuit power, but this would be auxiliary power to our communication cubicles, communication racks, or control and protection systems. This is to get the auxiliary power to the cubicle so it’s energized so we can start testing, communicate with other cubicles, or to verify instruments in the field prior to the first startup of the main circuit power – prior to energization of the 230 kV main bus system. First power during pre-commissioning energizes the auxiliary power systems to get them up and running and communicating so we can proceed with more pre-commissioning tests.

Loop checks on our electrical systems are then required. Cold loop checks are done before first power. This includes point-to-point checks to make sure that all the cables are terminated correctly. Hot loop checks after the first energization is where we confirm that one cubicle is correctly communicating with the next cubicle, or that instruments are correctly interfaced to our PLC controllers. The loop check is essentially having the PLC send a signal to the instrument to ensure that it responds and that we’re getting the right status signal back to the PLC, confirming the loop signal path between our communication cubicles and our instruments in the field. This is also known as operational loop checks, to confirm that we can control the status of a motor where we can turn it on, we can turn it off, and we’re getting the correct status back to the PLC.

Loop checks confirm the installation of the cubicle, the cable, as well as the instrument in the field. We can confirm that all devices are calibrated correctly, and this is confirmed back to the HMI system. For example, if we have a 4 to 20 milliamp device in the field, confirm that the device is scaled correctly, being displayed properly on the HMI, in the correct ranges, and that alarm setpoints are correct for that particular instrument. For each LL, L, H, HH setpoint, we confirm that we’re getting the right alarm triggers as we move the signal up and down within its range, confirming that we get the correct alarm notifications at the HMI. We’re also confirming that we’re getting the proper alarm routing into the alarm logs so that operators can view the status of the equipment as it’s triggering the various alarm set points. 

Phase Checks

In the example of an open-air switchyard, we confirm that the AC phase is connected correctly before energizing any of the bus work. This may be a visual inspection where we confirm the risers are properly connected between the overhead lines and the bus work. In smaller systems, we may perform measurements to confirm electrically that systems are connected correctly. In very large systems, such as many kilometers or miles of transmission line, we may need to drive the line and confirm that at various points of phase rotation, by the end of the line, the phases are correct for the line, and it’s connected to the proper bus work within the station. I’ve seen this caught last minute where phases were incorrectly rolled, and we want to avoid that situation because that can certainly cause a lot of damage.

Transformer Checks

Large oil-filled transformers require pre-commissioning, such as taking an oil sample before energization as well as after energization and comparing samples. This will tell us if there’s anything that’s not functioning correctly within the transformer such as hot spots or any off-gassing. The second oil sample compared to the first will show if there are any contaminants in the oil which could be an indication that there’s something wrong inside the transformer that requires further investigation.

In the factory, winding resistance and transformer ratios are verified. But once our transformer arrives on site, these parameters will be measured again to confirm that nothing was dislodged during transport. Any incorrect readings could indicate that something has moved inside the transformer and requires an internal inspection to confirm there’s no damage during shipping or installation.

It’s always a fun day when we do open circuit tests and short circuit tests. These are elaborate test setups to apply a significant short to the transformer. These tests allow us to measure the no-load losses and the full load losses. These are quite specialized tests and require a specialized test setup. Join an experienced team that’s done this before to see it in real-time and learn exactly how to execute these complex and more dangerous tests.

Protection Relay Testing

For monitoring faults within an AC switchyard or other AC apparatus, protection relay testing is performed. The first thing to do is to apply the protection relay settings which were supplied by our engineering team. They would have determined the coordinated protection settings for all the equipment apparatus, and control and protection devices and breaker throughout the electrical system. All of these coordinated settings need to be applied to the various equipment so that equipment is tripping off at the right levels based on other equipment within the system.

These settings are applied, and then each setting is confirmed that the settings are correct by performing PT and CT current injections both on the primary and secondary sides, to confirm that the various voltage and current levels are being read by the relay correctly and that the correct settings are applied to trip at the appropriate levels. This is confirmed back to the HMI where the PT and CT injections are displayed. The ranges and setpoints are confirmed as well, to confirm the various alarm trigger points.

Interlock Verification

Interlocks are an important aspect to verify during pre-commissioning. Interlocks provide a critical safety protection mechanism on electrical equipment, to prevent damage from occurring due to incorrect operation. As an example, say we’ve got two switchgear lineups with a tiebreaker in between. The tie breaker can only be closed if one of the main utility feeds is disconnected. If both utility feeds are connected one to each switchgear, then the tiebreaker cannot be closed – interlocks are established to prevent this from happening. If both incoming utility feeds are closed, the tiebreaker cannot be closed. These configurations are verified to confirm that interlocks are functioning correctly before applying main power to the switchgear lineup. If interlocks are not correct, then potentially we can be creating a very hazardous situation that’s not safe to work around and can potentially damaging equipment. There will be a whole series of interlocks to be verified on some systems, with every sinlge interlock to be verified to ensure that they’re functioning correctly in the field before applying main circuit power.

Motor Tests

Motor tests are commonly tested during pre-commissioning. One of the first things to confirm is that the AC phase is correct. We don’t want the motor spinning backwards or potentially causing damage to the motor. This is often confirmed through measurement but could be visual as well. For very large motors, the winding resistance is important to measure. This confirms that whatever was measured in the factory is still measured on-site. A motor bump test is completed. This is to confirm that power is connected correctly to the motor. Power is aplied for a very brief moment, and confirms that the motor is spinning in the right direction. This gives an initial indication that power feeds are correct, and confirms that when we turn on the power and leave it on, it’s not going to cause any damage. The motor is then run under no load, which is called an uncoupled run (uncouple from the pump), for a period of time to measure the performance of the motor – measure the voltage and current under no load.

We then proceed with a coupled run (motor connected to the pump) under load. The same measurements are taken. If the pump is pumping water through a pipe, flow and pressure can be measured. Three points on the pump curve are measured to confirm the pump and motor performance over the entire load range that the pump is designed for.

Hi-Pot Tests

High pot testing is often another test that’s done on-site. This test confirms that the dielectrics are meeting technical requirements. The high pot test applies a large voltage across the dielectric, and the leakage current is measured. The leakage current is required to be zero or very low. If the leakage current is higher than expected, then the dielectric may need to be replaced.

Battery Discharge Tests

Many electrical systems have a DC battery backup. Battery systems are connected to an AC charger and a DC distribution system. Battery rooms typically have an exhaust system to vent any gases that cells are generating. Once installation is complete, cycle testing on the batteries is performed where bcells are fully charged and fully discharged through multiple cycles to confirm that the AC charger is correctly interfaced with the batteries and that the battery cells are providing power as expected. Load testing then confirms the capacity of the batteries, which includes applying a temporary load and discharging the batteries over a period of time to confirm the capacity of the battery system. Trip testing is preformed, where the system is tripped off to confirm that the DC distribution system picks up and continues to energize the equipment.

Balance of Plant

Some other electrical systems you might come across are releated to balance of plant systems. These are related to building systems – life safety systems such as HVAC or emergency lighting, or perhaps a public address system, or a fire detection system. These are systems to support the building and the shell of the building in order to get the occupancy permit and be able to use the building further for other commissioning activities. Often, these are vendor package systems where the vendor completes the design, the installation, as well as the commissioning. From a commissioning perspective, we want to ensure that the vendors are performing their commissioning activities correctly, that they’re testing fully, there are no gaps in what’s being tested, and systems are signed off at the end and handed over to commissioning.  By doing this, we’re confident that building systems are complete, all the life safety systems are correct, and that we can integrate these systems into the more complex process commissioning.

Deficiences

As we proceed through any of these pre-commissioning activities, we will encounter deficiencies. The goal is always to have zero deficiencies, but I’ve never seen that actually happen. It’s quite common to find deficiencies as we go through the process, and when we do, there’s a process to categorize and track those deficiencies. Anything that’s encountered that doesn’t meet contract requirements is either a Type-A, Type-B, or a Type-C deficiency.

A Type-A deficiency is something that needs to be addressed right away. It presents a functional issue or a safety issue that must be addressed before any further commissioning can proceed. A Type-A deficiency is something that’s going to stop our commissioning activities and needs to be fixed right away.

A Type-B deficiency is something that needs to be addressed, but doesn’t necessarily impact commissioning activities right away. A Type-B deficiency allows commissioning to proceed, and must be complete prior to hand over to the owner.

A Type-C deficiency is something that’s minor in nature. This could be a paint scratch or a hole in the drywall or something cosmetic. It really has no bearing or functional impact on the systems. It does need to be addressed, but could be addressed at a later date even after hand over to the owner, during the warranty period.

This process of categorizing each deficiency as they’re identified ensures nothing is missed and that issues are addressed and closed. The old way of tracking these was to create an excel spreadsheet and try and track them manually. I’ve never seen that go well, it’s a nightmare especially when you’re getting projects that have a significant amount of snags, a significant amount of deficiencies – so please don’t use a spreadsheet or paper to try and track these deficiencies. There are much more sophisticated and superior software packages that can help you manage deficiencies and ensure nothing gets missed during pre-commissioning. There are several little things that will get identified. And while an item may seem small and have no impact, all the little details matter during pre-commissioning and commissioning. We need to make sure all issues are tracked and closed correctly so they don’t become much bigger issues later in the process.

Pre-Commissioning Complete

At the end of pre-commissioning of a particular subsystem, the commissioning team confirms that all checklists are filled out and that all results are passing within tolerance. This confirms that pre-commissioning is complete and that all systems are contract compliant before we move into the next phase of commissioning. This is, of course, a stagged process – where many systems are at various stages of completion and commissioning.  Commissioning of one system may be taking place while other systems are still undergoing construction or pre-commissioning. But for this particular subsystem, we’ve determined that pre-commissioning is complete, and it can then be used for further integration into larger systems for more commissioning.

Question and Answer

Is construction the same as electrical installation, correct?

Yes, that’s correct. Construction and installation would both be similarly used terms. Our construction team is definitely going to be installing a lot of the equipment. Their focus is on installation at an equipment level which is great. This is what we need as we transition from construction installation toward pre-commissioning. The thought process changes a little bit where the focus isn’t so much on equipment, the focus is on the system or subsystem. One piece of equipment isn’t all that useful to us for commissioning, we need a whole group of equipment to form a subsystem or system. I’ll just point that out that the thought process changes a little bit from construction to commissioning in that we need to be having a systems-based thought process in completing our systems so that we can build up the system and get it ready for the owner.

Does it mean that without handover or mechanical completion from grounding, there will be no pre-commissioning?

There are some activities that the construction team will complete from a pre-commissioning standpoint, particularly some of the mechanical systems something as pipe flushing, pressure testing, and leak testing because those are done during different stages of installation before the piping is actually complete. Some of those pre-commissioning activities are actually identified in a construction ITP for those groups to complete mechanical completion, then define the point where the construction team is completing their scope of work. And the pre-commissioning team and commissioning team can move on and start testing some of the systems. You’re, right. If there is no mechanical completion, then that means the construction team isn’t completing their scope of work and the system can’t be handed over to commissioning. Mechanical completion and the definition of that milestone exactly what it is critically important so that everybody knows what they need to do, when they need to do it, and what that hand over from one group to the other signifies.

Sometimes, we have to make a deal with construction to give a system priority over construction packs, just a comment from one of our electrical students.

For sure, yep. That can definitely be the case and when we say make a deal, we want to avoid kind of that sort of deal-making because that’s one of the biggest reasons to have the commissioning team involved much earlier in the project. We’ve outlined the priority well ahead of when those handovers are to take place, a year or maybe two or well in advance. We’re going to identify what are those construction priorities, what does the construction team need to hand over first, what do they need to hand over, and what is the sequence for handover from the construction team to the commissioning team. When I hear the term deal that seems like maybe a last-minute sort of arrangement, and we want to avoid that where it’s well known well in advance what the priorities are so that there are no surprises. We don’t need to be making those kinds of deals now, certainly. There are things that are going to happen on-site. There are procurement delays, unknown issues that are encountered, and things might change. That could be where you need to talk to your construction team and make a deal to work around some of those issues that are encountered. Definitely, it is critically important that the construction team and the commissioning team are communicating very closely and working very well together. We don’t want to see any competing priorities. We don’t want to see any big egos. We want very clean and collaborative communication between the two groups so that we can navigate these issues as they arise and do what’s in the best interest of the project.

Kindly give some overview of FEED and P&IDs as well as a bill of materials.

FEED stands for Front End Engineering Design, and it’s the first or one of the early stages of the project where the design team is taking the project concept and developing that further into an actual design, drawing, manufacturing drawings, a drawing set, a drawing package, and design details that can be used for later phases of the project to actually manufacture and install the equipment and eventually start testing the equipment. During the FEED process is when the commissioning team wants to get involved to help the engineering team understand some of the priorities that are required and the sequence of the engineering deliverables, the order that needs to be created to align eventually with the end startup sequence of the project. It can be sometimes a very likely lengthy phase of the project to complete that front-end engineering. But critical to have that early stage of the project aligned with the startup sequence at the end of the project so that the right deliverables from engineering are being presented to construction. Then, construction is presenting the right deliverables to commissioning in the right order that lines up with the sequence.

A P&ID is a piping and instrumentation drawing. It’s essentially a mechanical drawing that shows the mechanical piping layout where some of the instruments are installed within the piping, how the piping is interconnected to valves and pumps, and basically the process flow of your particular plant process. It’s a very useful drawing. It would be I guess a counterpart to a single level single line drawing. In the case of our electrical world, the P&ID gives the mechanical layout of the plant and how is interconnected. You’ll hear of the term a P&ID walkthrough, that’s the process of taking that drawing out in the field visually confirming that everything’s installed correctly. It can be as simple as just highlighting on the drawing. There are more sophisticated ways to do it too and confirming that every instrument is in place, all piping is in place, everything’s interconnected for pumps and valves, and essentially installation is complete from a mechanical standpoint prior to moving into testing of those systems.

Bill of materials would then be just the list of pieces of either equipment or material that is used to make up that particular system be an electrical system or a mechanical system. You would have your listed materials of this type of gauge of wire, communication cubicle, valve, and pump listing out the specific part number description and quantity of that item. Essentially, it’s your shopping list to say this is what you need to go buy in order to build this system. I hope that answers your question.

What is not clear to me is the electrical system boundary, its hierarchy, and its priority.

Boundary isolations are critically important from a commissioning safety perspective and from a lockout tagout perspective. We can have electrical systems that are interconnected in many ways through communication cables, power cables, high voltage cables, low voltage cables, DC cables, AC cables, and there could there are certainly many boundaries that could separate one system from the other. When the system is all complete all those boundaries are removed, and it’s one system. But during this critical overlap of construction and commissioning, there are certainly situations where construction is still taking place in one area of the plant while commissioning is proceeding in another, and those boundary isolations are critically important to ensure that those boundary isolations are maintained and that nothing’s being energized into an area where another group is working. The process of identifying those boundary isolations is through the lockout tagout process where you get access to the most accurate current up-to-date set of IFC drawings which is the redline drawings.

The redline drawings are going to indicate anything that was potentially changed in the field. If there was a design change or a field wiring change, if there was a rolled wire or something that needed to be changed, we get access to those most current redline drawings so that we have the most current information, and then the review of that drawing from a very technical perspective. We’re going to identify what are the isolations that need to take place in order to maintain that boundary across all of those signals, all of those voltage levels from one area of the plant to the other that are identified and passed to our lockout authority. Our LOTO managing group, they’re going to review and confirm that particular LOTO request with others going other activities going on in the plant. It may be during construction or during later phases of commissioning to evaluate if there are any other simultaneous operations that are taking place that need to be evaluated, and the LOTO authority will determine, yes.

This particular lockout tagout can be granted for this period of time to maintain that boundary isolation, then once that’s determined any particular locks that need to be applied to the equipment to lock those out, and then a tag identifying who owns that lock is applied to that piece of equipment. That could be locking out a breaker, that could be locking out a valve, anything to maintain or ensure that any hazardous energy is maintained at that boundary isolation. When you talk about hierarchy and priority that’s the role of the LOTO authority to manage all the various lockout tagout requests, ensure that the proper hierarchy is maintained, and any priority is given. It could be the case where a particular LOTO request can’t be granted at that time because there’s other equipment that’s locked out and it is a higher priority. So, that particular LOTO request may not be able to take place this week, it might have to be pushed till next week, or however, that can be fit into the situation. This is definitely a very important topic particularly during pre-commissioning as construction is still being completed and needs to be a strong focus of everyone involved in the project to ensure that our boundary isolations are maintained.

The main problem is when the project manager does not understand he needs us, the commissioning team, at an early stage.

You’re, absolutely right. We hear this all the time as those projects aren’t bringing in commissioning early enough. They view it as an extra expense, right. Why do we want an additional person on-site? Commissioning isn’t until two years from now. Why do we want to pay for another two or three or four people this early in the project? What are they going to do? And you’re right that’s just a complete lack of understanding of commissioning, and how it works because if the commissioning team is only mobilizing to the site when it’s time to start commissioning well, it’s too late by then. All the commissioning team can do is identify issues rather than two years ago proactively identify issues work with the teams and ensure that commissioning goes smoother later by doing that. Unfortunately, your project manager is costing the project lots of money by not having the commissioning team involved earlier, then that’s not setting the commissioning team up for success on really complex projects.

It can sometimes take a year or more to plan out the sequence of commissioning and ensure that it’s going to go smoothly. We definitely want the commissioning team involved earlier, and it’s a constant challenge to raise awareness, show the value of commissioning, and that’s one of the reasons that we’re here today. Why I’ve been giving this live webinar is to raise awareness and help people understand the value of commissioning so that we can get into projects a bit earlier, help save money on projects, and help them deliver on time. So, I’ll keep sharing that message, you keep sharing that message. The more awareness we can get, the more we can help our projects to succeed.

Has anyone been using dynamics 365 as a CMS completion system?

That’s not one that I’ve particularly used in the past. There are several that exist on the market some of which have recently been developed. Say, in the last few years that are fantastic, that are built on revolutionary technology like big data technology and really leverage the systems that exist today. There are some that are more maybe created 10 years ago, 20 years ago that are more so legacy systems. But you really need to evaluate the needs of your project and the size of the system that you need. Some of the systems that exist today are amazing. I’m just surprised by the amount of features, and how they can leverage the data that’s available on the projects to help us manage our projects. Actually, this was the topic of our previous webinar on Benefits of Commissioning Software.  I encourage you to go back and check from our January webinar where we went through that in a lot more detail. You can check on commissioningstartup.com I’ve got a good article on commissioning software as well as a list of the current software vendors that are out there. I don’t have dynamics 365 listed but that’s probably a good one to add to the list.

Being an INC operation and maintenance engineer, how can I learn and switch my career to INC as an electrical commissioning engineer?

Operations is a much-needed skillset in the commissioning team. We can sometimes see engineers that are participating in commissioning, and maybe they’re really smart engineers but they lack that operational on-site hands-on experience. I definitely encourage you to make that transition because having that operational background and operational experience is a key skill set to have as part of our commissioning teams. It’s an understanding of the owner’s needs and requirements and an understanding of how the plant is going to be operated for decades to come after it goes into service. I encourage you to take that operation knowledge that you have and apply that to commissioning. How do you do that? A great way to do that is to start learning to understand the commissioning processes. We’ve got lots of great resources at commissioningandstartup.com from free resources to paid resources that you can check out and see what’s the best fit for you.

Getting that fundamental understanding of how the commissioning process works and what are the steps in it is critical before you actually get to the site and do the commissioning. That knowledge baseline is critical to have. I see some people get to the site where they’re new to commissioning. They don’t understand the commissioning process, but they’re trying to execute commissioning on-site and it’s a bit of a struggle without having that underlying background and knowledge of what the commissioning process is. I really suggest that to be your starting point is check out some of our resources, and how we can get you started and help you point it in the right direction. Once you get that baseline knowledge, then that’ll help you join another project where you can continue to learn on-site, get your hands-on experience, and continue your learning process. One thing I’ll say is, that commissioning is really a commitment to lifelong learning. There’s no ability to learn everything in a six-month period, and then you’re set for life. Commissioning is always learning daily, continuing to get more knowledge about the systems, getting more knowledge about the process, and keeping up to date on our skill sets as projects continue to get more and more complex.

Can Type-B and C punches be a showstopper?

I would typically say no because if it’s a Type-B or a Type-C, and you’re indicating it as a showstopper, then likely that should be a Type-A deficiency. A Type-A deficiency would be something that the pump is just physically not installed. Well, there’s nothing we can do about that the pump needs to be installed that’s a Type-A deficiency. Installation is not complete so we want to identify that as a Type-A. If something’s a Type-B but it’s still holding you up from commissioning, then you should probably look at reclassifying it to a Type-A deficiency. This is always a debate everybody I sit through. Too many meetings where we just want to debate is this a Type-A, is this a Type-B deficiency, and it’s always a debate. You want to set up some sort of determination process. You’ll see in a lot of contracts where the engineer has the final determination. So, that contract role of the engineer when those disputes arise inevitably of is this a Type-A, is this a Type-B that’s taken to the engineer. The engineer will make that final determination and say, “No, this Type-B really should be a Type-A, guys. It’s reclassified, go get it done.”

During the motor solo run, who should be in charge? Electrical commissioning team or mechanical commissioning team?

Good question! Can be either. I would probably say that there’s a skill set of each involved in that particular run. Getting the motor up and running is probably an electrical commissioning team member function given that it’s the first point in time where we’re interfacing power to the motor, getting it energized, operating in the right direction so that would be an electrical team function. Once the motor is running and driving a pump, then probably some of the mechanical team is involved because they’re going to want to confirm pressure rates, flow rates from the pump, measure the three points on the pump curve, and determine that the pump is running correctly. There are aspects of both involved. I wouldn’t necessarily say who’s leading it, one versus the other because it’s a team effort. We want the right skill sets involved from both a mechanical and electrical perspective.

When we’re starting up those systems, that involve both disciplines, we’ll definitely want to get the right people involved for other systems that don’t have any mechanical components. It may strictly be your two or three electrical team members that you’ve got looking after those activities. Same for mechanical, if it’s a mechanical startup activity, then your mechanical guys are going to get involved while the electrical guys are working on something else. It’s always equipment specific, and the commissioning manager’s role from a day-to-day perspective is to make sure that the right people are involved, the right people are seeing our system startup, and that we’re getting the right results from our systems.

What about the PTW work permit prior to electrical commissioning activities?

Yes, the permit to work is a critical part of our lockout tagout process. What I described earlier when we’re applying to our lockout, tag authority to request a certain outage or shutdown and gets our equipment locked out. When the lockout tagout authority reviews that and basically gives permission to have that outage at that particular time. What they’re issuing is a permit to work. Say, the construction team needs to be working on a particular set of equipment next week starting Monday till Friday, and they need it locked out, they’ve made that application in advance of the equipment that they need to be locked out, that the motor or the power feed that they need to be locked out. The lockout tag authority is going to review that and say, “Yes, no problem. Next week, starting Monday at 8 a.m. you can. We can have that equipment cleared, and here’s your permit to work to do that work.”

The permit to work will identify the dates of when the outage starts, and when the outage ends. The permit to work will also identify the keyholder responsible to maintain that lockout. The individual actually doing the work on the equipment at the end of that outage, then the PTW is surrendered back to the lockout tagout authority essentially saying that the work is complete, they’ve removed their locks from the system, and that the equipment can be re-energized. The permit to work is definitely an important part of our lockout tagout process are about to maintain our boundary isolations for these critical shutdowns or outages.

Is a continuity check the same as a point-to-point check?

Why the pre-commissioning team is part of the commissioning team? I always know them as two separate teams.

Yes, and that can definitely be the case where you’ve got, and it often is the case where you’ve got a dedicated pre-commissioning team and a dedicated commissioning team because these activities are going to be overlapped. The pre-commissioning team is going to be working on a specific subsystem, and once they’re complete, they’re going to move on to the next subsystem to complete. Their specialization is pre-commissioning, they’re going to focus on going from one system to the next, to the next, and doing their pre-commissioning. The commissioning team is maybe a different set of people that are coming in behind them and performing commissioning or integrating those systems with other areas of the plant. It can definitely be a definite, separate team structure in how you want to set that up. That’s not always the case, sometimes on smaller projects, it’s the same group that oversees one system from start to finish, from the beginning of testing to the end of testing.

It depends on how large the project is, and how you want to structure the project. It depends on the skill sets that are involved, the skill sets of the team, and how best to use those. The commissioning manager is definitely going to review that to determine who they’ve got on the team, what skill sets they need, and who should be going through the various sequences of testing. And often, it may be a separate pre-commissioning team from the commissioning team.

Can hazardous inspection hold pre-commissioning or commissioning process if the inspection has not been accepted yet?

Absolutely, yes because as we go through pre-commissioning and commissioning will get to startup placing these systems in service. If that particular hazardous inspection needs to be done before the equipment is energized, then it must be done. That can be sometimes the reason to identify something as a Type-A deficiency if it’s going to require a significant outage to rectify or address at a later point in time. We may not get that outage for a few years during the next routine maintenance, so it must be done now before systems are placed into service. If an outstanding inspection is classified as a Type-A deficiency because it’s going to have a significant shutdown or outage required, then as a Type-A deficiency that must be done before we can proceed with any further pre-commissioning or commissioning activities.

How do you define the commissioning skyline steps timeline plan activity in any particular process? Can you explain in general?

I’m not familiar with the term skyline but a timeline plan definitely is, and this is something we go into great detail. We had a great discussion about this on Monday during our Commissioning Academy discussion. The short answer is essentially the commissioning team is going to determine the startup sequence for the plant. There really is only one path that you can go through to startup a lot of the equipment. When we go through the high-level sequence, we’re going to know that we need AC power before we energize HVAC. We know that we need the 230kv switchyard energized and operational before we can energize the 230kv synchronous condenser. We know that the AC must be fully commissioned and ready before we can energize the HVDC components of the system at a very high level.

There’s only one way to go through the sequence. It can’t be that you’re going to energize the HVDC stuff, but the AC switchyard isn’t going to be available for a year later. It just doesn’t work. You need your power in infeed and outfeed into your AC switchyards before you can do the HVDC. From a technical standpoint, it’s going to dictate that you need this system before the next commissioning team is going to help put that together at that very high level. When you break it down into details. you’re going to see that one particular AC control building within that AC switchyard is required before you energize AC bay number two or whatever that technical dependency is to build up the system. The commissioning team is going to define this, and that’s going to help some of the earlier groups the construction team and the design team understand how the systems are going to be energized and started up, and therefore which ones need to be built in what priority and which ones need to be designed in what priority. From a timeline plan that’s how it’s all going to fit together.

Once you get further down into the details on a particular system in that overall high-level sequence, you’re going to see that you need to have mechanical completion complete on this particular piece of equipment. Then, you’re going to go through the pre-commissioning activities as you define them in your checklists, and then you’re going to go through commissioning or integration with other systems in your system. And it’s all a technical dependency on what portion of the project is required and needed to move on to the next stage of commissioning. The commissioning team is the only group that can define that because it’s entirely dependent on how the commissioning team wants to start up and energize the new systems. Nobody else can define that. The construction team can’t say, “Well, no you’re going to energize it in this order.” It doesn’t work like that. It has to be energized in a certain sequence because of the technical dependencies of what the next system requires. I hope that answers your question.

What does the sequence of managing redline markup drawings?

Often, I see this done in a manual process where you might set out a master set of printed e-size drawings, and there’s one group that maintains that hard copy set of drawings. Through construction that would be an individual within the construction team that’s marking those up in red ink or green ink for anything that’s changed on that drawing. That’s how it’s been done for years. Now, there are better ways to do that where it’s electronically because when you have a printed hard copy set of drawings, then that’s in one of the construction tailor’s trailers that everybody’s got to go see, and it’s a bit of an old legacy process. I still see it exists because it works. But a lot of the digital systems that exist now, allow us to track that online where there’s still one master set of drawings but at least everybody can log into the system, see those drawings, and not have to run around the site trying to find that one magical hard copy set of drawing that sometimes goes missing too. That process of managing during construction to mark up those red lines that’s one of the key deliverables at mechanical completion is to hand those red line drawings over to the commissioning team. Then, the commissioning team becomes the owner of those drawings to continue keeping them accurate for any issues that are discovered during commissioning, any changes that are made and mark up, any additional changes to those drawings so that at the end of commissioning when the drawings are or the systems are put into service, we have that accurate set of red line drawings.

We can leave a copy with the operations team while those redline markups are sent to the originator of that drawing to incorporate those redlines into a CAD version of drawings which then becomes the as-built set of drawings that the operating team uses for the life of the plant. Having that most current as-built configuration in the drawings, in the as-built, then operations can work with that for years to come.

Any special consideration in regard to some potentially destructive testing?

Sometimes required for power cables, transformers, generators, and motors during pre-commissioning. Some potentially destructive testing can always be the case. Yes, I’m thinking of when we were talking about the open circuit or short circuit test where we’re applying a large, short to a large rotating machine, there are always hazards that could exist where if the protection systems don’t operate as they’re supposed to applying that large short could potentially cause damage. Before we get to that point, we’re definitely going to want to verify during our pre-commissioning that all of our CTs, PTs, protection relay, and everything’s set up correctly so that we have the highest degree of confidence that our protection systems are going to work correctly.

When we actually apply that full short to the system that’s going to mitigate the risk that if when that short is applied our systems don’t react correctly, and we can cause damage to the systems. Anything that we can check at a lower level to confirm that all of our protection systems are in place. We definitely want to confirm another potentially destructive test. I can think of is we’ve done line HVDC line fault testing in the past where you apply a fault to a DC line, and you’re basically creating your own lightning. If the protection systems at either end of the transmission line don’t react correctly, then we can potentially damage the HVDC converter systems. We don’t want to do that. So, prior to applying that DC fault to the line, we’ve verified anything and everything that we possibly can at the station level to confirm that all our protection systems are going to operate correctly to mitigate that risk of potentially destructive testing. We want to basically build the system up in as many small steps as we can. Verifying every little step along the way so that we have the highest degree of confidence that when we apply the potentially destructive fault to the system, the systems are going to react appropriately and not cause any damage.

Do you find commissioning is similar from OGC to tech and semiconductor sectors?

I don’t know if I’ve thought about that before. Let’s think about that for a second. I can definitely see the similarity in getting some of these large facilities set up and running like a large semiconductor plant is definitely going to have significant elements of pre-commissioning and commissioning to get that plant up and running. The actual semiconductor plant that’s operations I would consider more similar to operations of a plant process so, kind of post-commissioning activity. There are certainly similar skill sets involved in both, and there can be comparisons that are drawn between them. If you’re looking at comparing those two industries and considering transitioning for one from one to the other I can definitely see that there’s a correlation in those skill sets that are involved and potentially things that are learned from one can be applied to the other and vice versa.

Short circuit and arc flash analysis study, are these part of commissioning activities or requirements for the power systems energization?

I often see that analysis or design of the systems such as performing an arc flash study that would be something that your engineering team performs. The engineers being the group that designed the systems planned and set all of the protection coordination settings between switchgear, breakers, transformers, CTs, PTs, relays, and protection settings based on their study of all those protected coordinating studies and settings. They’re also going to do an arc flash study based on those protected or coordinated settings through an arc flash analysis. You’re basically going to determine the incident energy that is available within each cubicle or a particular piece of equipment. Say, if a breaker needs to be racked in or racked out or a cubicle door needs to be open to access equipment in there. There’s a particular set of incident energy that’s available in that cubicle determined by the voltage levels that are available, the current that is available, as well as how fast a lot of the coordinated protection settings are going to react to that particular fault. The engineering team I’ve seen in every case has done that particular study to determine the arc flash hazards that exist within that particular cubicle based on that. Then, a label is applied to the outside of the cubicle before any of this stuff is energized.

Those hazards are identified on the outside of cubicles so that from a commissioning team perspective when we’re working with these systems during pre-commissioning or commissioning. If we need to access equipment to troubleshoot a breaker, issues we need to rack out a breaker rack in a breaker, we need to know the incident energy that’s involved and how to do those activities safely. That would be something that’s determined by the engineering team. The same thing with a short circuit test or an open circuit test, the engineering team would have designed the particular equipment to accommodate or react or behave dynamically to these certain types of events. They’ll be the ones that have defined that they’ll be the ones that will study the results of it commissioning team will execute the test and probably give those results back to the engineering team to review, analyze,, and confirm that the transients involved in that particular test are within their design tolerance and behaving appropriately. During these types of tests certainly, the commissioning team and the engineering team are going to work very closely together. The commissioning team would be managing and executing the particular test on-site. It’s very likely in all cases that someone from the engineering team is there as well to witness the test, participate in the test, evaluate results in real-time, and help make those decisions on what should take place if there are any issues that are encountered.

For motor solo run with a decoupled motor mechanical should be present to check for noises and lubrication of the bearings. This is my method, what do you think about it?

I, agree. Yes, for anything that could potentially present any mechanical issues that’s a fairly short test. To do that mechanical run, you’re probably going to want the right discipline expert involved to participate in that test, certainly for vibrations noises lubricants. The mechanical experts on your team are definitely the ones that are in the best position to help and provide guidance if there are any issues that are encountered there. The electrical team is going to focus on their electrical activities and make sure that nothing’s missed. It’s a good thing to have your mechanical individual there as well because he’s going to potentially notice something that the electrical team members may not. Absolutely dependent on the test that’s being involved. You want to call in the right experts, and make sure they’re there willing and able to participate and can provide their expertise to help diagnose or identify any issues with the equipment. It’s always better to identify issues at that point in time than three months later when that pump is being used or motors are being used for actual plant processes. If we’re hearing noises or there’s no lubricant in the bearings, well that’s a bad thing to discover while we’re trying to start up the plant. We want to catch those earlier. By having your mechanical team members there, they’re going to help to identify those earlier issues.

How do you prioritize when different activities go at the same time simop?

The commissioning team is a key contributor to this process to help identify that, particularly in a brownfield project where there are in-service assets, and we’re trying to bring new assets into the system. That’s a perfect example of simultaneous operations. The in-service assets will always take priority because we can’t be inadvertently disrupting in-service equipment. In-service equipment must be maintained so that we can maintain the performance of the current implant processes. But there may be situations where in order to complete a particular commissioning activity we do need to take an outage or a shutdown, and in that case, those need to be planned very closely to determine that this system, this in-service existing brownfield piece of equipment needs to be taken out of service for three days so that we can tie in our new electrical or mechanical plant process system. In that case, where there are simultaneous operations taking place, we need to plan those pretty closely to plan that shutdown. Make sure it happens on the days that are planned, and make sure that we don’t extend past the end of the outage because that may not be a possibility.  

We must be returning the equipment back to service on the dates that are promised to the point where you may be even want to have an extra day of contingency. It’s always better to return a system back to service earlier than to be at the end of your outage, try, beg, and plead for an outage extension because you may not be able to get it and the outage may not end. I can think of an example where we had to take an outage on a large uh international uh 500 kv transmission line and the only time to take that outage was in a shoulder season between the heating and cooling seasons. The only date we could get for that outage was a particular three days in May, and this was planned months in advance almost a year in advance to determine when that outage was going to take place. Those were the dates we couldn’t determine the day before that we needed to delay that outage which means, “Okay, you wait a year next May. Let’s try again.” Some of those have to be prioritized from that perspective, and then to make sure that the work is complete within that three-day outage. For some of the smaller activities where there are maybe multiple systems being started up at the same time, the commissioning team needs to be planning that and essentially determining the startup sequence of the plant so that this system’s going to be started up first. Then, next week this system is going to be started up. If commissioning is disorganized, and commissioning is requesting to start up two systems on the same day, well I would say that’s the commissioning team’s fault for not planning that out appropriately.

From a commissioning team perspective, we would never propose that but when there are other in-service assets in the plant we need to be planning and managing our activities knowing what else is going on in the plant so that all simultaneous operations are taking place without disruption. The best part of commissioning is planning out the complexity of how this is all going to fit together and is one of the main reasons to have the commissioning team involved earlier in the project. This requires some thought if you have the commissioning team showing up a few days or a few weeks or even just a couple of months before some of these activities are going to take place. You’re not going to have an opportunity to plan these simultaneous operations. Things are going to go wrong, things are going to be disorganized, and uncoordinated, and take that to your project manager. Help them understand, explain to them why the commissioning team needs to be involved earlier the complexities of planning simultaneous operations, and the thought process that needs to take place earlier in the project so that we can avoid these disruptions in the plan by finding out that potentially some things can’t happen at the same time due to simop.

How do we categorize and or the starting point needed in commissioning a data center specifically for the communications and electrical system?

You’re going to look at the technical dependencies of what system is required first prior to the next system. Some of your auxiliary systems, your fiber optic communication systems, communication systems, any protection systems, electrical systems, building systems, the balance of plant systems, and just the lighting within the data center, those you’re going to need first based on what some of the next activities are going to take. Of course, you’re not going to be able to test your data servers and your cubicle racks if you haven’t got your fiber up and running. You’re not going to be able to test your remote communications if you’ve got your fiber system is still missing when we categorize or prioritize some of those systems.

We know that in order to do the full server rack communication, we need our fiber systems interconnected between our server racks. We need our fiber ring going off-site so that we can control and communicate with other systems. It’s strictly going to depend, a data center would be no different than any other industrial plant process where we need to identify from a technical standpoint, what systems we do we need first in order to fully commission the next system, and the system after that. In the case of a data center, all of those building systems are going to be needed life safety systems to get an occupancy permit for the building. The building doing something useful as in all the data communication racks and data servers within the building that would come, kind of post-building completion or post-occupancy permit. I hope that helps a little bit. I know that it’s a bit more complicated than that when you get into the details and specifics of the design of your data center. But once you get into those specific details, you’ll see from a technical standpoint what’s required prior to the next system in order to be able to fully commission it.

What is the best pre-commissioning systematization philosophy, equipment-wise or to follow energization sequence? Upstream cb and cable, and transformer and downstream cb? What is your experience?

The philosophy I follow is to always start at the various high level of the project. Look at the highest-level single-level diagram that you can find of the plant or the highest-level P&ID system of the project, and you’re going to want to start there, at the big block chunk of the project you know that you need. I’ll use this example again; you know that you need the 230 kv AC switchyard before you can fully commission any of the HVDC components of the project. Starting at that big block high-level picture of the four or five or six main components of the project is going to give you your first outline of what needs to be commissioned first, what needs to be commissioned second, what needs to be commissioned third. That’s going to allow you to then dive into deeper the particular components that make up one of those big block systems. If you dive a bit deeper into your 230 kv AC switchyard system, you’re going to see the various equipment and functions that make up that system. You’re going to get down to maybe one of the AC bays, one of the ring bus connected breakers that form that 230 kv ring bus, and then you can even drive down deeper to get right to the equipment level where you identify that particular breaker number three.

That’s the philosophy I use to determine when that specific piece of equipment needs to be tested because that’s going to allow you see to see how it fits up into the bigger level higher-level process of the plant if you start the other way around. If you start right at an equipment level, of course, that’s the first thing you’re going to test during pre-commissioning is the 230kv breaker. But you don’t necessarily have that picture of how it fits up into the overall hierarchy of the plant by starting at the big block picture and then, drilling down into the details that are going to help you see where that breaker fits into the overall big picture plan, and therefore, where that particular piece of equipment needs to be tested in the sequence so that’s the philosophy I use. It seems to work well to at least get to that high-level big picture of how this all fits together, and it’s not a quick process. What I described there could potentially take a year to map out a project of that size and to get down to that very specific equipment level, and the sequence that needs to take place. But through that year-long process, you’re going to be able to fit all the pieces of the puzzle together into this big picture, and how you’re going to go through your commissioning and startup sequence to build up the end product of the plant.

During an emergency, generator endurance test of 72 hours, should the load be 100 or the minimum load required to run the engines like 40 or 50 percent?

That’s going to depend on your contract maybe, and the requirements for that endurance test. Your contract may require the various loads to be applied over that 72-hour run. You’re certainly going to want to follow whatever your contract says about how that endurance test is going to be run. Now, that’s not always the case. The contract may be silent on that and say, do an endurance run test. If that’s the case, you’re going to look at the risk involved and the potential damage that could occur. If this is a large emergency generator, and large currents are being applied, and this is the first time that it’s being run, I would suggest you probably step that in various levels if that’s one level or two levels at the various current loading before you get to under 100 loading. Maybe, that’s not the full 72 hours. Maybe, you’re going to step it up in a series where the first hour you’re going to run it at 25. In the second hour, you’re going run it at 50 or maybe run it at three hours but based on your risk tolerance and risk of damaging equipment that’s going to help you gauge how fast you want to push that or how quickly you want to get to a 100 percent load.

If this particular emergency generator has a six-month lead time, then I’d be fairly cautious. I’d maybe run that at a lower current load limit for a few hours before stepping it up to 100 load. This is something we would have done in the past where we’re loading the various equipment in our HVDC system that we’ve commissioned in the past where there were three heat runs that were defined at various load limits. You’d run the heat run for a few hours at 25, 75 percent, and then 100. I think it’s a good idea to step through the various load limits until you can mitigate that risk and gain confidence that the equipment’s not going to be damaged once you get to 100 load and for a few more hours of testing. It’s good risk mitigation to step that up and gain that confidence before getting to full load. If that equipment’s damaged and six months to replace it, well it was probably worth taking a few extra hours to confirm that that’s not going to be the case because that can be disastrous if we don’t have that piece of equipment for six months. Have to try and replan the project to start up the plant without or another some sort of configuration, without that piece of equipment, and despite our best efforts, there is always infant mortality if we get to that 72-hour run time at full load. And on the 70th hour, there’s a major equipment failure at least by stepping it through our various loads, we did our best to mitigate that risk. But there’s always infant mortality that is hard to plan around. It’s like it’s an unknown, but we want to mitigate the chance of that happening by potentially seeing any issues at lower load levels before the 70th hour potentially having that infant mortality issue, and having a major equipment failure.

At the turnover stage, what are the requirements for the system dossier?

Very good question, and maybe everybody’s least favorite part of the project. At the end of the project, everybody wants to congratulate and move on to the next project to do some more exciting commissioning. But there’s always a closeout period where we have to gather documentation, put it in a manageable fashion, and hand it over to the owner so that they can use this information for the operation of the plant for decades to come. Often, this has been a very daunting task if not managed well during construction and commissioning. It can be quite a mess to gather up all the documentation and put it in a nice package to hand over to the owner. There are far superior systems that exist to help manage this and if used properly can significantly reduce the level of effort required at the end of commissioning for turnover where all of our O&M manuals, redline drawings, test results, operating procedures, and switching procedures, those will be the bulk of what would exist within that turnover package to the owner. Essentially, anything that they would use for operation on a day-to-day basis would go in that turnover package. They’re not necessarily going to need things like the historical project information such as RFIs, change notices, and project letters. Those types of things, they’re not going to reference those on a day-to-day basis. That sort of history may be captured somewhere in the project archives but not necessarily used by the operators on a day-to-day basis.

They’re going to need more things like the O&M manuals to define how to operate the equipment, how to maintain it, and the maintenance intervals that are required in the drawing packages for troubleshooting any issues encountered on site. Those types of things are going to go into the turnover binders, turnover binders being the historical term. But out of our commissioning management software systems to hand over to the owner that they can use ongoing for the life of the plant. The turnover information is really we want to get away from the hard copies, the printed binders, and I should stop using that term because all of our files are going to be electronic. Electronically searchable so that we can navigate through the immense amount of information or operations can navigate through it to find the information that they need. That’s really the process at the end of the project. If you can leverage a CMS, that will significantly make it easier for you to go through this turnover package process at the end of the project rather than spending months and months trying to gather up all this information, hiring some poor summer student to wade through all this information and make sense of it all, while everybody’s trying to get out of there and skip on onto their next project. So, that would be my recommendation.

It’s great to see everybody’s engagement and super interest in pre-commissioning and commissioning. I’m happy that you’re here to be part of this commissioning community. Join us for our next live webinar. We’re always looking for great ideas on what the commissioning community is looking for and how we can help provide you with the information that you need to be able to commission our complex projects. I trust you found this information helpful.  Thanks, everyone for your great participation!

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