Achieving PRC-028-1 &

NOGRR255 Compliance with the

SEL-2240 Axion & SEL RTAC

An in-depth technical guide from the Keentel Engineering substation services team on designing, installing, and commissioning a compliant Digital Fault Recorder (DFR) system for inverter-based resources using the SEL-2240 Axion distributed I/O platform and the SEL Real-Time Automation Controller (RTAC).

1. Why These Standards Exist: The IBR Visibility Gap

Over the past decade, several major grid disturbances including the Blue Cut Fire, Canyon 2 Fire, and the Odessa events in Texas revealed a systemic problem: when inverter-based resources (IBRs) such as solar, wind, and battery storage plants tripped or reduced output during grid faults, operators and engineers frequently had no high-resolution data to explain what happened. Protection relays at conventional plants had long provided oscillography, but IBR facilities were often built with minimal recording capability, no unit-level visibility, and inconsistent time synchronization. Event investigations stalled, models could not be validated, and the same failure modes repeated across the fleet.

Two regulatory instruments now close that gap. NERC PRC-028-1 Disturbance Monitoring and Reporting Requirements for Inverter-Based Resources became effective April 1, 2025 and establishes mandatory Sequence of Events Recording (SER), Fault Recording (FR), and Dynamic Disturbance Recording (DDR) for applicable IBRs across North America. In Texas, ERCOT NOGRR255 amended the Nodal Operating Guides effective August 1, 2024 with closely aligned disturbance monitoring equipment (DME) requirements, plus obligations for data retention, data provision to ERCOT, and ongoing maintenance and testing. Together with the ride-through requirements of NOGRR245 and the performance standards PRC-029 and PRC-030, these rules create a closed loop: high-resolution data captures what happened, ride-through criteria define what should have happened, and corrective-action processes fix the difference.



The practical question for asset owners is no longer whether to install disturbance monitoring, but how to do it economically at dozens of sites that were never designed for it. This guide presents the architecture Keentel Engineering deploys most often for brownfield and greenfield IBR facilities: the SEL RTAC + SEL-2240 Axion Digital Fault Recorder, a solution SEL documents as designed to exceed compliance with NERC PRC-002 and PRC-028.

2. Who Is In Scope, and When

Because the PRC-028-1 dates vary by facility category, here is the full matrix:

A point owners frequently miss: because the NOGRR255 retention and provision obligations are already live, a facility with any existing recording capability (relay event reports, RTAC SER logs) must already be retaining that data and be able to deliver it to ERCOT on request. An interim-compliance configuration of the existing relays is therefore a standard first step in every Keentel deployment, protecting the owner during the construction window.

3. What the Standards Actually Require: SER, FR, and DDR

Both frameworks organize disturbance monitoring into three data categories, each with specified locations, trigger conditions, and performance minimums.

3.1 Sequence of Events Recording (SER)

SER is the time-stamped digital log of discrete events. PRC-028-1 R1 requires circuit breaker positions for breakers associated with the main power transformer(s), collector bus(es), and shunt reactive devices, and at the IBR unit level all fault codes, all fault alarms, and high/low voltage and frequency ride-through mode status, recorded when triggered by ride-through operation or tripping. An important nuance in the final standard: for IBR units already in commercial operation before the effective date, the unit-level data applies if the units are capable and acceptable evidence includes equipment specifications or a letter from the manufacturer documenting capability or the lack of it. Timing accuracy under R6 is ±1 millisecond of UTC for recording devices and ±100 milliseconds for IBR unit device clocks; ERCOT's NOGRR255 language is tighter still (GPS-based sub-microsecond timing for fault recording), so in Texas the design should be built to the ERCOT numbers.

3.2 Fault Recording (FR)

FR is triggered oscillography raw AC voltage and current waveforms captured around a disturbance at the main power transformer high side, the collector feeder breakers, and any shunt dynamic reactive devices. PRC-028-1 R2 requires phase-to-neutral voltages, phase and residual currents, and real and reactive power on a three-phase basis for each of those elements. The NERC performance floor in R3 is 64 samples per cycle but NOGRR255 raises it to 128 samples per cycle for any fault recording equipment installed or replaced after January 1, 2024 (legacy equipment set as close to 128 as it allows). Records must include at least 2 cycles of pre-trigger data, with a total record length of at least 2 seconds under PRC-028-1 and at least 5 seconds under NOGRR255 design to the ERCOT number. Mandatory triggers: neutral (residual) overcurrent (NOGRR255 sets the pickup at 0.2 p.u. of rated CT secondary or less), AC phase undervoltage (below 0.9 p.u. for two cycles or longer), AC phase overvoltage (above 1.1 p.u. for two cycles or longer), phase overcurrent at 1.5 p.u. or less or protective relay tripping for all protection groups (cross-triggering from relay operations), and  under PRC-028-1 R3 over- and underfrequency at the main power transformer and collector feeders. A design note on unit-level oscillography: early PRC-028 drafts contained a 128 s/c fault-recording requirement at IBR units on the last 10% of each collector feeder, and that language circulated widely but the final adopted standard does not include unit-level fault recording; the final unit-level obligation is the SER-type data described in 3.1. Verify the corresponding ERCOT unit-level language against the final approved Operating Guide before scoping inverter-skid recording hardware.

3.3 Dynamic Disturbance Recording (DDR)

DDR captures the slower electromechanical and control-system dynamics continuously: per PRC-028-1 R4, for each main power transformer — one voltage, the corresponding current, real and reactive power on a three-phase basis, and frequency. R5 sets the performance: input sampling of at least 960 samples per second and an output recording rate of at least 60 times per second. Continuous recording with a rolling retention buffer is the cleanest way to satisfy it.

3.4 Retention, Format, Delivery, and the Obligations People Miss

PRC-028-1 R7 requires data retrievable for 20 calendar days and provided within 15 calendar days of a request; NOGRR255 goes further a rolling 30-calendar-day retention and delivery within 7 calendar days of a request unless the requestor grants an extension. Design to the ERCOT numbers and both are satisfied. Formats are fixed: SER in ASCII CSV per the standard's Attachment 1 field order (Date, Time, Local Time Code, Plant Name, Device, State), FR/DDR in IEEE C37.111 COMTRADE (1999 revision or later) or CSV, files named per IEEE C37.232 COMNAME (2011 or later). Three obligations owners routinely miss: (1) any data actually provided to ERCOT, the Regional Entity, or NERC must then be stored for at least three years; (2) NOGRR255 requires a current DME equipment database location, type, make/model, operational status, monitored equipment, and the complete monitored-points list deliverable within 30 days of request; and (3) under PRC-028-1 R8, a discovered failure of recording capability must be restored within 90 calendar days or covered by a Corrective Action Plan submitted to the Regional Entity, while NOGRR255 adds a 30-day data-availability verification cycle (or an automated failure-notification system) and 30-day failure reporting. These are operational programs, not hardware which is why the deliverable set must include a data-provision procedure and a maintenance & testing plan, not just a commissioned recorder.

4. The Solution Architecture: SEL RTAC + SEL-2240 Axion DFR

4.1 Why This Platform

A traditional standalone DFR is a single centralized chassis with every CT and PT circuit hauled back to one panel. That model works, but at an IBR collector substation it usually means long secondary cable runs, a large panel footprint, and the real killer on brownfield sites dependence on spare CT cores that often do not exist. The SEL Axion inverts the model: compact, modular acquisition nodes are placed close to the signals, and a deterministic EtherCAT network carries time-aligned samples back to a central SEL RTAC that performs all recording, triggering, retention, and file generation. Per SEL's published specifications, the platform scales to 192 analog channels or 1,728 digital channels, records triggered oscillography at up to 24 kHz with 24-bit resolution, continuously records at 3,000 samples per second for more than 20 days, streams synchrophasors at up to 120 messages per second, and stores as many as 500,000 SOE records with 1 ms accuracy with native IEEE C37.111 COMTRADE output and IEEE C37.232 COMNAME file naming.

Critically, every AC analog input module in an Axion system samples at precisely the same instant, with sub-microsecond alignment across nodes and when connected to IRIG top-of-second synchronization across geographically dispersed locations. For disturbance analysis, that means every voltage and current in the plant shares one time reference without post-processing.

4.2 The Hardware Building Blocks

4.3 Storage Sizing Do the Math Before You Order

Continuous Recording Groups are storage-hungry: each voltage or current channel configured for continuous recording consumes roughly 600–700 MB per day at 3 kHz. A typical single-transformer collector substation lands around 30 analog channels — call it 20 GB per day — so the 20-day regulatory minimum needs about 400 GB, and a comfortable 45-day design target lands near 900 GB. A 2 TB SSD covers that with margin; SEL offers drives up to 8 TB for the SEL-3555, SEL-3560E, and SEL-3350 where multi-transformer stations push channel counts higher.

5. Installing an Axion Node per Transformer: Step-by-Step

The design pattern Keentel applies most often is one Axion node per main power transformer position (covering the high-voltage interconnection and the transformer itself) plus one node per collector bus (covering the medium-voltage bus and its feeders), all reporting to a central SEL-3555 RTAC in the control house. At a single-transformer collector substation that is two nodes; at a two-transformer station, three to four. Here is the full workflow, from paper to energized recorder.

Step 1 Define the monitored areas from the single-line diagram

Start with the SLD and mark every location the standards require: the high-voltage line/POI, the main power transformer high and low sides, the collector bus, each feeder breaker, any capacitor banks or dynamic reactive devices, and the IBR units on the last 10% of each feeder. Each marked location becomes a set of CT/PT signals and digital points, and every CT/PT group maps to an Axion analog module. Best practice: over-mark now and leave chassis slots empty a nine-slot SEL-2242 node rarely needs to ship full, and empty slots are free expansion for the future feeder positions most collector stations reserve.

Step 2 Verify the RTAC and order the right parts

Four hard gates decide the bill of materials check them before anything is purchased:

1. Firmware: the DFR extension requires RTAC firmware R153-V0 or later (Continuous Recording Groups arrived at R152). Older firmware means a planned upgrade, coordinated around the RTAC's existing SCADA and gateway duties.
2. EtherCAT interface: an SEL-3555 needs a free PCI slot for the SEL-3390E4 Network Adapter Card (or SEL-3390T Time and Ethernet Adapter Card) — this card is the dedicated EtherCAT port to the Axion network.
3. Licenses: confirm FileIO, DDR, and Continuous Recorder licenses; add ACSELERATOR RTAC SEL-5033 v1.37.153.8000+ and SEL-5601-2 Synchrowave Event on the engineering workstation.
4. Storage: size the SSD from the channel count (600–700 MB/day/channel at 3 kHz continuous) against your retention target 30 days is the ERCOT floor (20 under NERC alone), 45 days is a comfortable design point.

Step 3 Plan the CT/PT connections (and decide conventional vs. split-core)

At the transformer node, the SEL-2245-42 (3CT/3PT) module takes conventional 1 A/5 A CT secondaries and up to 300 V PT inputs with two-wire connections the standard approach where spare CT cores or shared circuits with verified burden exist. Where they do not most commonly at feeder positions on brownfield sites specify the SEL-2245-43 with non-intrusive split-core CTs: the clamp-on CTs install around existing conductors without breaking a single secondary circuit, and field calibration compensates the gain and phase error the split-core introduces. This one design decision routinely eliminates the largest outage and rewiring cost in a retrofit. Perform a CT burden check on every shared circuit, and land all new wiring through test switches with shorting provisions for safe future maintenance.

Step 4 Mount the nodes and build the EtherCAT network

Each node is a SEL-2242 chassis (rack, panel, or surface mount, modules vertical with 0.5 in clearance) fitted with an SEL-2243 power coupler (dual couplers for redundant AC + DC station supplies), the analog modules, and a digital input module. The network rules are strict and worth memorizing: EtherCAT is non-routable the connection from the RTAC's EtherCAT port to the first node's power coupler Port 1 must be direct, with no Ethernet switches, and subsequent nodes daisy-chain coupler-to-coupler. Copper RJ45 links are limited to under 3 meters (panel-internal only); LC fiber reaches roughly 2 km multimode or 15 km single-mode, and backplanes can be linked as far as 5 km apart which is also what makes remote nodes at inverter skids feasible over site fiber for the unit-level 128 s/c requirement.

Step 5 Wire the digital inputs

Bring every breaker 52A contact, disconnect switch status, relay trip/operate output, and station alarm into the SEL-2244 module at the nearest node. These become 1 ms SER points and for breakers falling-edge fault-record triggers, so a breaker opening captures a full waveform record even if no analog threshold tripped.

Step 6 Configure the DFR in SEL-5033 (no code required)

The DFR Extension turns configuration into a menu-driven workflow SEL documents configuration time dropping from days to under an hour. The sequence:

1. Enable EtherCAT on one port of the SEL-3390E4 card via the RTAC web interface (the port becomes dedicated to EtherCAT).
2. Create an RTAC project (firmware R153+) and insert the Digital Fault Recorder extension from the Extensions menu.
3. Set General Settings: nominal frequency, phase rotation, station name, fault recording rate (24 kHz recommended), record length (e.g., 6 s with 2.5 s pre-trigger margin over the ERCOT 5-second total-record floor and the 2-cycle pre-trigger minimum), continuous-recording retention duration (e.g., 45 days), and enable the synchrophasor server.
4. Define the Axion nodes: chassis size and the module in each slot, then enter every CT and PT ratio as X:1 (a 1200:5 CT is entered as 240; a wye-connected 700:1 PT as 700).
5. Define substation assets and associate them with modules: the HV interconnection as a Transmission Line asset (voltage + current + impedance-based fault location), the transformer high and low sides as Generic assets (the asset type SEL lists for transformers, inverters, reactors, and capacitor banks), feeders as Transmission Line assets, and voltage-only points as Bus assets.
6. Set triggers per asset: voltage triggers (a common pattern is 105% overvoltage / 95% undervoltage with a 16 ms pickup), overcurrent, sequence-component triggers (V1 low, I2/I0 high catch unbalance and ground events), and over/underfrequency triggers (with positive and negative ROCOF) on the main power transformer and feeder assets frequency triggering at the MPT and feeders is explicitly required by PRC-028-1 R3. Enable relay-trip cross-triggering from all protection groups via the digital inputs.
7. Configure digital inputs (channel names appear in the event records name them properly), enable falling-edge triggers on breaker inputs, and map inverter fault codes, operating-mode changes, and HVRT/LVRT/HFRT/LFRT ride-through flags as custom channels any tag already in the RTAC project (for example from the plant controller or inverter SCADA) can be embedded directly into the DFR records.
8. Toggle Build DFR to True and save: the extension automatically generates every recording device, Continuous Recording Group, PMU, channel, calculation, and all IEC 61131-3 logic. The finished project must compile with 0 errors and 0 warnings.

Step 7 Commission and prove it end-to-end

A compliant recorder is one you can demonstrate, not just install. The Keentel commissioning sequence:

• Time synchronization validation: GPS startup report, IRIG-B signal verification at every device, and timestamp comparison of all IEDs against UTC. The DFR's Synchronized status indication confirms high-quality IRIG-B or PTP at the RTAC and all connected analog modules.
• Secondary injection trigger tests at each asset: prove every voltage, overcurrent, sequence, frequency, and digital trigger produces a correctly named COMTRADE record with intact pre-trigger data.
• Retrieval demonstration: generate an on-demand Continuous Recording Group file from the RTAC web interface (select date, time, duration, and channels — 3 kHz, PMU, and digital) and download fault records from Event Collection; export SOE and fault-location CSVs from the file manager. This same workflow becomes the documented ERCOT 15-day data provision procedure.
• Retention validation: verify storage headroom and the rolling-buffer behavior against the retention target; confirm the DFR Alarm logic (EtherCAT abnormal, CPU burden over 75%, storage under 10%/4 GB, RAM under 10%) is mapped to SCADA.
• Documentation closeout: as-left RTAC project backup, settings files, channel schedule, trigger settings document, test reports, and the maintenance & testing plan — the audit evidence package.
  

6. Compliance Mapping: Requirement to Platform Capability

7. Beyond the Checkbox: What Owners Actually Gain

Treating this purely as a compliance cost misses the operational value. With a commissioned RTAC + Axion DFR, an Apparent Performance Failure investigation under ERCOT's ride-through rules with its 90-day plan and 180-day implementation clocks starts from complete, time-aligned data instead of guesswork. Impedance-based fault location on the interconnection line shortens patrols. Continuous PMU data feeds model validation and oscillation analysis. And because the entire configuration lives in one templated, no-code SEL-5033 project, the second site in a fleet deploys in a fraction of the engineering hours of the first. Keentel Engineering provides the full lifecycle gap analysis, design, procurement, installation, commissioning, and the audit-ready evidence book as a turnkey substation service.

Case Studies

Case Study 1 Brownfield 100 MW Solar Facility: DFR Retrofit Without Rewiring a Single Feeder CT

Background

A 100 MW-class utility-scale solar facility in the ERCOT region interconnected at 138 kV through a single collector substation: one three-winding main power transformer, a 34.5 kV collector bus, and four medium-voltage feeder circuits. The site had been built several years earlier with a strong protection and automation backbone SEL line, transformer, bus, and feeder relays, an SEL-3555 RTAC serving as SCADA gateway, a GPS clock with IRIG-B distribution, and a fiber LAN but no dedicated disturbance recording device of any kind. A third-party compliance review had flagged the disturbance recording methodology as undefined and the largest outstanding gap against PRC-028-1 and NOGRR255, with time-synchronization commissioning evidence also missing.

Challenge

• No spare CT cores existed at any of the four feeder positions — a conventional centralized DFR would have required breaking in-service secondary circuits, extended outages, and significant rewiring cost.
• The existing SEL-3555 was mission-critical for SCADA and plant control interfaces; any DFR duty added to it could not jeopardize those functions.
• NOGRR255 retention and data-provision obligations were already legally in effect while the project was still in design — the owner had exposure during the construction window.
• The owner needed audit-grade evidence, not just hardware: settings files, commissioning records, and procedures were all absent from the site records.

Solution

Keentel designed a two-node SEL-2240 Axion DFR reporting to the existing SEL-3555. Node 1, in the control house, carried SEL-2245-42 AC Protection Modules wired conventionally to the 138 kV line PTs and transformer high-side CTs (where spare secondaries existed) plus an SEL-2244-2 digital input module for breaker positions. Node 2, at the medium-voltage switchgear lineup, used an SEL-2245-43 12-channel module paired with non-intrusive split-core CTs clamped around all four feeder circuits and the bus PTs — zero secondary rewiring, with field calibration compensating split-core gain and phase error. The nodes daisy-chained on LC fiber back to an SEL-3390E4 EtherCAT card added to the RTAC, which was upgraded to R153 firmware with FileIO, DDR, and Continuous Recorder licenses and a 2 TB SSD. Fault recording was set at 24 kHz — above both the 64 samples-per-cycle NERC floor and the 128 s/c NOGRR255 requirement for equipment installed after January 1, 2024 — with a 2.5-second pre-trigger and 6-second records for margin over the ERCOT 5-second total-record floor. Continuous Recording Groups ran on all station channels with a 45-day retention target, comfortably above the rolling 30-calendar-day ERCOT requirement. Trigger settings followed the verified floors: voltage more sensitive than the 1.1/0.9 p.u. thresholds, residual overcurrent, over/underfrequency at the transformer and feeder assets per PRC-028-1 R3, and relay-trip cross-triggering from all protection groups. Inverter fault codes, mode changes, and ride-through flags already flowing through the RTAC from the plant controller were mapped as DFR custom channels — embedding the SER content requirements directly into the COMTRADE records. As an interim measure delivered in week two, Keentel configured and documented the existing relays' event recording and retention so the site met the already-effective NOGRR255 obligations during construction.

Implementation Highlights

• Total on-site outage exposure: one four-hour window at the transformer position; the four feeder circuits required no outage at all thanks to the split-core approach.
• DFR configuration through the SEL-5033 menu-driven asset model — line asset with impedance fault location, transformer generic assets, four feeder line assets with voltage (105%/95%), sequence-component, and frequency/ROCOF triggers — compiled at 0 errors / 0 warnings.
• Commissioning proved the full chain: secondary-injection triggers to COMTRADE, on-demand CRG web retrieval, timestamp verification of every IED against UTC, and a live demonstration of the ERCOT data provision workflow against the 7-calendar-day NOGRR255 clock, including SER export in the Attachment 1 CSV field order. The closeout package also delivered the DME Equipment Reporting Database and a maintenance & testing plan built around the PRC-028-1 R8 process (restore within 90 days or file a Corrective Action Plan) with the 30-day data-availability verification implemented through automated DFR-alarm-to-SCADA notification.

Results

Lessons Learned

Treat the first site as a product, not a project: every hour invested in templating the asset model and test plans pays back multiplied across the fleet. Confirm legacy RTAC capability early discovering mid-project that an installed controller cannot host the DFR extension wrecks both budget and milestone sequencing. And read the final standard, not the draft: the unit-level requirement changed materially between the circulated drafts and the adopted PRC-028-1, and re-baselining to the final language cut meaningful hardware cost from the program.

Case Study 3 Greenfield Solar + Storage Hybrid: Compliance Designed In, Not Bolted On

Background

A developer building a solar-plus-battery hybrid facility in the 200 MW class solar PV and a co-located BESS sharing a collector substation with two main power transformers and a 34.5 kV bus with six feeder positions plus dedicated storage feeders engaged Keentel during detailed design, before the substation package was released for construction. As a new BES IBR with commercial operation after April 1, 2025, the facility fell under the accelerated new-resource schedule R1 through R7 compliant by July 1, 2026 or commercial operation, whichever is later, with R8 already in effect since January 1, 2026 so disturbance monitoring had to be operational at COD, and the interconnection agreement's ride-through obligations referenced IEEE 2800-aligned ERCOT requirements from synchronization.

Challenge

• Two transformers and mixed solar/storage feeders pushed the channel count well beyond a small retrofit the DFR had to be sized, not assumed.
• BESS inverters introduce bidirectional flows and fast mode transitions (charge/discharge/idle, grid-support functions); SER had to capture mode changes and ride-through flags with enough fidelity to defend performance during commissioning-era grid events.
• The construction schedule offered no room for DFR rework: CT/PT allocations, panel space, fiber routes, and the EtherCAT topology had to be right on the IFC drawings the first time.

Solution

Because the facility was still on paper, compliance was engineered into the base design. Each main power transformer received its own Axion node the one-node-per-transformer pattern with SEL-2245-42 modules on dedicated DFR CT cores and PT windings specified into the equipment procurement (no split-core compromise needed on a greenfield). A third node covered the collector bus and all feeder positions, with slots reserved in each SEL-2242 chassis for the expansion feeders in the site's later phase. The central SEL-3555 was specified from day one with the SEL-3390T time-and-Ethernet card, DFR licensing, and storage sized by calculation: roughly 45 analog channels at 600–700 MB/day each set the SSD requirement, with the platform's 192-analog-channel ceiling and the above-96-channel SEL-3555 requirement both checked against the phase-two build-out. The EtherCAT fiber topology direct RTAC-to-node, no switches, node-to-node daisy chain was drawn onto the raceway and fiber schedules before construction. BESS and PV inverter fault codes, fault alarms, and HVRT/LVRT/HFRT/LFRT ride-through mode status were mapped as DFR custom channels from the plant controller integration — and because these were new units, the “if capable” relief available to existing fleets did not apply: unit-level SER capability per PRC-028-1 R1 was made a factory-acceptance requirement with both inverter OEMs during procurement rather than discovered after energization. Fault recording was configured at 24 kHz with 6-second records, and retention at 45 days against the rolling 30-day ERCOT floor. Redundant time sources (GPS primary with a second source under the platform's PTP/IRIG redundancy support) eliminated the single-point time-base failure.

Implementation Highlights

• Zero DFR-driven change orders during construction the CT/PT, panel, and fiber provisions were on the IFC set from the start.
• DFR commissioning ran inside the substation commissioning window; the end-to-end trigger-to-COMTRADE-to-retrieval demonstration including Attachment 1 SER CSV export and the 7-calendar-day ERCOT provision workflow was witnessed as part of energization testing, and the data-provision procedure, R8-ready maintenance & testing plan, and DME Equipment Reporting Database were in the operator's hands at COD.
• During an area grid disturbance in the first months of operation, the recorder captured time-aligned 24 kHz records and inverter mode flags across both transformers — the facility demonstrated compliant ride-through from its own data, closing the inquiry without a corrective-action process.



Results

Lessons Learned

On a greenfield, the cheapest disturbance monitoring program is the one specified before steel is ordered: dedicated CT cores cost almost nothing at procurement and a fortune after energization. Engage the inverter OEMs on unit-level SER capability during factory coordination new units get no “if capable” relief and let the DFR channel math, not habit, size the RTAC hardware and storage.

Frequently Asked Questions

Lessons Learned

The CT question decides the retrofit economics resolve conventional-versus-split-core per position during the gap analysis, before the BOM is priced. And treat the already-effective NOGRR255 obligations as day-one scope: the interim relay-recording configuration cost a few engineering hours and removed months of compliance exposure.

Case Study 2 Multi-Site Wind Fleet: Legacy RTAC Replacement and a Template That Scale

Background

A renewable owner-operator held a fleet of wind facilities in the 100–200 MW class across ERCOT and neighboring regions, most built in the early-to-mid 2010s. The sites shared a familiar vintage architecture: SEL feeder and transformer relays, capacitor banks with their own relays, and older-generation RTAC hardware — including SEL-3505 units at several sites — serving as SCADA gateways. Facing the PRC-028-1 fleet milestones (50% by January 1, 2029 and 100% by January 1, 2030 for existing BES IBRs) and NOGRR255's faster equipment clock at the Texas sites, the owner needed a repeatable program, not a series of one-off projects.

Challenge

• The legacy SEL-3505 RTACs could not perform the fault recording or dynamic disturbance recording functions the standards require — a hardware replacement was unavoidable at those sites, and existing SCADA logic had to migrate without disrupting operations.
• Wind turbine generators were distributed across kilometers of collector feeders, and unit-level obligations were a moving target: the owner had scoped its program against draft-era language requiring 128 s/c oscillography at units on the last 10% of each feeder, but the final adopted PRC-028-1 contains no unit-level fault recording — the final unit-level obligation is SER-type data (fault codes, alarms, and ride-through mode status), and for units in commercial operation before the effective date it applies only if the units are capable.
• Fleet-level milestone accounting: the owner had to sequence which sites counted toward the 50% tranche and prove progress to its compliance organization.
• Each site had different feeder counts, CT ratios, and cap-bank arrangements — but the owner's budget assumed template reuse, not bespoke engineering per site.

Solution

Keentel executed a pilot-then-template program. At the pilot site, the legacy RTAC was replaced with an SEL-3555 running R153+ firmware with the SEL-3390E4 EtherCAT card and DFR licensing; existing SCADA logic and protocol maps were converted into the new project so the gateway function carried over intact. A control-house Axion node (SEL-2245-42 modules) covered the main power transformer and 34.5 kV bus; a second node covered the feeder lineup and the capacitor bank — the cap bank defined as a Generic asset exactly as SEL's asset model intends for reactive devices. For the unit level, the program pivoted to the final standard's actual requirement: Keentel obtained OEM capability documentation for every turbine converter model in the fleet — manufacturer letters and equipment specifications that, under the “if capable” provision for existing units, are themselves acceptable compliance evidence — and integrated the available fault codes, alarms, and ride-through mode status tags from the turbine SCADA into the RTAC SER and DFR custom channels with no new field wiring. At two sites where the owner elected unit-level oscillography for its own ride-through analytics, compact remote Axion nodes at selected pad-mount locations were linked over existing single-mode fiber — comfortably within EtherCAT's roughly 15 km single-mode reach — recording at 24 kHz, with deterministic EtherCAT and IRIG top-of-second synchronization keeping the remote measurements time-aligned with the substation channels. Every design artifact — asset model, trigger templates (including ROCOF triggers tuned for the weak-grid corner of the system), channel schedule format, panel drawings, test plans — was built as a fleet template.

Implementation Highlights



• Pilot site: 26 weeks including the RTAC replacement and SCADA migration; template sites thereafter averaged 16–18 weeks.
• Engineering hours per site fell by roughly half from the pilot to the third deployment — the direct payoff of the SEL-5033 no-code asset model and template reuse.
• OEM capability letters closed the unit-level obligation for the majority of the fleet at documentation cost only; the elective remote turbine-pad nodes recorded at 24 kHz for the owner's own analytics. Because R8 took effect for BES IBRs on January 1, 2026, every site's DFR alarm logic (recording stopped, storage low, EtherCAT abnormal) was mapped to SCADA — the automated failure detection that both the 90-day restore-or-CAP process and NOGRR255's 30-day verification obligation assume.
• A fleet milestone tracker mapped each commissioned site against the NOGRR255 2-year/4-year and PRC-028-1 2029/2030 dates, giving the owner's compliance team defensible progress evidence.

Results

Ready to start your own compliance program?

Keentel Engineering's substation services team delivers gap analysis, DME design, procurement, installation, commissioning, and audit-ready documentation for PRC-028-1 and NOGRR255 for a single site or an entire fleet. Visit www.keentelengineering.com to schedule a consultation.