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HomeMy WebLinkAbout20190730Dempsey Direct.pdfDAVID J. MEYER VICE PRESIDENT AND CHIEF COUNSEL FOR REGULATORY AND GOVERNMENTAL AFFAIRS AVISTA CORPORATION 141I E. MISSION AVENUE P. O.BOX3727 SPOKANE, WASHINGTON 99220 PHONE: (509) 495-4316, FAX: (509) 495-8851 RECEIVED ff19 JUL 30 Plt 2: l8 r . ',ii.-: I':llllC', l' ; i . :, ;,]'.-,i.:,,'llSSl0i'l BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE POWER COST ADJUSTMENT (PCA) ANNUAL RATE ADJUSTMENT FILING OF AVISTA CORPORATION ) ) ) ) CASE NO. AVU-E-lg-cg DIRECT TESTIMONY OF THOMAS C. DEMPSEY FOR AVISTA CORPORATION 1 I. INTRODUCTION 2 a. Please state your name, business address, and present position with 3 Avista Corporation. 4 A. My name is Thomas C. Dempsey. My business address is l4l1 East 5 Mission Avenue, Spokane, Washington, and I am employed by the Company in the 6 Generation Production and Substation Support Department. My title is Manager, Thermal 7 Operations and Maintenance. 8 Q. What is your educational background and prior work experience? 9 A. I am a 1993 graduate of the University of Texas at Austin with a Degree in 10 Mechanical Engineering. I completed my Masters degree in Renewable Energy and 1l Sustainability Systems in 2019 from Penn State University. I started my career as a 12 performance engineer at Houston Lighting & Power in Houston, Texas. While working 13 there I participated in equipment performance testing activities on a number of gas-fired 14 steam facilities, a coal facility, and several simple-cycle gas turbine facilities. I started 15 working for Avista in December 1996 as a mechanical production engineer in the 16 Generation Production Substation Support Department. [n that capacity I participated in a 17 wide variety of hydro and thermal generating station projects. In2007 I joined the Power 18 Supply Depa{ment where I managed Avista's share of the Coyote Springs 2 and Colstrip 19 Generating Station facilities. ln 2014 I rejoined GPSS where my primary responsibilities 20 include operations and maintenance management for all of Avista's thermal generating 2l facilities. For the last23 years at Avista I have had a number of engineering and supervisory 22 roles related to our thermal generation fleet. Dempsey, Di Avista P. I a. What is the scope of your testimony in this proceeding? A. My testimony will describe the Mercury & Air Toxics Standards ("MATS") emission exceedance that led to outages that occurred at the Colstrip Generating Station, specifically Units #3 and #4. I will demonstrate that the outages that occurred were not the result of imprudent actions on the part of Avista, the other plant owners, nor the plant operator (Talen Montana). In support of that assertion, I will summarize Talen's actions as described in the September 17, 2018 letter to Montana Department of Environmental Quality (MDEQ). Finally, I will provide an overview of recent transformer concems at our Coyote Springs 2 Generating Facility and how the Company has and continues to address issues related to certain transformers. Company witness Mr. Johnson will discuss the estimated financial impact of the issues at Colstrip and Coyote Springs II in his testimony. a. Are you sponsoring any exhibits to be introduced in this proceeding? A. Yes. I am sponsoring Exhibits No. TCD-2 through TCD-4. Exh. TCD-2 is a copy of the August 31,2018 letter from MDEQ to Talen, "Request for information with Mercury & Air Toxics Standard". Exh. TCD-3 is Talen's September 17,2018, response letter to MDEQ related to the compliance with Mercury Air Toxics Standard for Colstrip. Exh. TCD-4 is a copy of the final Root Cause Analysis regarding the MATS issue at Colstrip. II. COLSTRIP UNITS 3 & 4 a. What is Avista's role in the planning, management and operation of the Colstrip plant? Dempsey, Di Avista P. 2 8 9 t0 11 T2 l3 t4 15 t6 t7 l8 t9 20 2t 22 23 1 A. Avista is a 1502 owner of the Colstrip Units #3 and #4, a twin-unit, coal 2 fired, generating facility, and is not directly involved in the day to day operations of the 3 plant. Avista, along with the other owners of the facility, and according to ownership 4 percentage, provide oversight of the facility. The operator, Talen Montana, plans and 5 carries out the daily operation of the facility. 6 Q. Please describe the environmental compliance issue at Colstrip that 7 caused the outage in 2018. 8 A. Mercury and Air Toxics Standard (MATS) became effective on April 16, 9 2017, for all Colstrip units. MATS provides that Particulate Matter (PM) emissions may 10 be used as a swrogate for estimating emissions of non-Mercury metals. Mercury emissions 1l are measured separately to meet a Mercury-specific limitation. 12 Talen currently performs compliance assurance stack testing for Colstrip on a 13 quarterly basis to meet the MATS site-wide limitation for PM emissions (0.03 14 lbs./MMBtu). Test results for Colstrip Units #3 and #4, performed on June 21, 2018, and l5 June 26,2018, respectively, indicated Colstrip was operating in excess of MATS limits as 16 included in Air Permit #0513-14 issued by the MDEQ. MDEQ was notified of the PM 17 emission exceedance on June 28,2018, and as a result, Unit #3 was immediately removed 18 from service. Similarly, Unit #4 was removed from service on June 29,2018. 19 Talen submitted a Final testing report confirming the non-compliance with MATS 20 to the MDEQ on August 20,2018. Talen proposed that limited operation of Unit #3 and 2l Unit #4 for the evaluation of a corrective action and/or data gathering related to potential 22 corrective action was a prudent approach to addressing the issue. Dempsey, Di Avista P. 3 I 2 J On August 31, 2018, the MDEQ issued a "Request for Information with Mercury & Air Toxics Standard", which has been provided as Exh. TCD-2. In that letter, the MDEQ stated: Talen Montana, LLC (Talen) conducted PM emissions testing at CSES [Colstrip Steam Electric Station] on June 21,2018 and June 26,2018 for Units 3 and 4, respectively. Test results indicated, and the Source Test Report submitted by CSES confirmed, that CSES was operating in excess of the applicable emission limit contained in Title 40 Code of Federal Regulations Part 63 (40 CFR 63) Subpart UUUUU, also referred to as the Mercury and Air Toxics Standard (MArs). MDEQ specifically requested information through six questions, as shown in Exh. TCD-2. a. Please summarize Talen's immediate actions taken to resolve the MATS compliance issue. A. On September 17, 2018, Talen responded to the MDEQ request for information by addressing the six questions related to the compliance with MATS. This response is provided as Exh. TCD-3. That letter provides a detailed description of the activities taken associated with the boilers and Venturi scrubbers after the emission exceedance occurred. In summary, an extensive inspection was conducted of the coal mills, boilers, ductwork, air preheater, scrubbers and the stack. Cleaning, adjustments and repairs were conducted, as needed which required Unit #3 to be offline from June 28-July 8 and Unit #4 to be offline from June 29-July 17. There were four main areas that were investigated to determine and address the cause of emission exceedance: o Compliance test method o Fuel quality o Boiler combustiono Scrubber performance In addition to Talen staff, nationally recognized expertise was brought on-site to Dempsey, Di Avista P. 4 4 5 6 7 8 9 10 11 t2 13 t4 15 16 l7 18 t9 20 2t 22 23 24 25 26 27 28 29 30 1 2 3 4 5 6 7 8 9 10 11 t2 13 l4 15 16. l7 18 t9 20 2t 22 23 24 help conduct the investigation and implement corrective actions. The PM compliance test method and procedures were verified by audit and independent side-by-side testing. A proximate and ultimate analysis was performed on the coal, and the results were within contract specifications. Coal mills were tested and adjusted to help reduce slagging/fouling. Overall boiler combustion was evaluated to ensure that SO3 mist and condensable PM were not being formed and emitted. Lastly, the focus tumed to overall scrubber performance which focused on three main areas - (1) liquid spray, (2) flue gas flow, and (3) scrubber chemistry. 1. Liquid spray flow - the wet Venturi scrubbers remove both PM and SO2 with proper spray flow to the multiple sections of the scrubber. All the sprays were inspected, evaluated and adjusted to achieve a more effective balance for emissions removal. 2. Flue gas flow - overall flue gas flow and distribution of the flue gas is important to effective scrubber operation. The mist eliminator section of the scrubber controls calry-over droplets from the wet scrubbing process. These droplets can contain solids which can contribute to PM emissions. Testing of the mist eliminator section of the scrubber indicated that the some eliminators were not optimally balanced, which resulted in higher areas of flow and the potential for carry-over. Talen immediately notified MDEQ of its plan to install new scrubber flow distribution plates to balance the flow across the mist eliminator section. 3. Scrubber chemistry - A review of scrubber chemistry, consisted of a review of the solids in the scrubber water, comparing current levels versus against historic levels. The solids were2-5oh above the historic operating ranges. New operating Dempsey, Di Avista P. 5 I ranges were immediately adopted to address this problem. 2 a. Were the measures taken in whole by Talen (with assistance of third- 3 party advisors) effective in returning Units #3 and #4 to compliance with MATS? 4 A. Yes, the measures were effective. On September 4, 2018, Unit #4 5 demonstrated compliance with MATS Standard with a PM emission rate of 0.021 6 lb./mmbtu. On September I l, 2018, Unit #3 demonstrated compliance with MATS 7 Standard with a PM emission rate of 0.024lb./mmbtu. 8 Q. What specific actions were most effective in bringing the Colstrip plant 9 back to within MATS compliance? l0 A. Talen inspected, cleaned, adjusted and repaired many potentially 11 contributing systems during their efforts to get Units #3 and #4 back to compliance as 12 quickly as possible. Talen considered it important to identify all potential PM contributors 13 and then review unit operating data and diagnostic test data in order help determine which 14 areas may or may not have contributed to the issue. The final Root Cause Analysis (RCA) 15 Investigation Report was issued on July 9,2019 and is included as Exhibit TCD-4. The 16 RCA report found that the elevated PM levels were likely due to a combination of the Fuel 17 Chemistry Variation, Boiler Combustion Conditions, Scrubber Solids Carry-Over and 18 Reactive Fiberglass PM Filters. The Executive Summary provides additional details for 19 each of these potential causes (see page 4), and a summary of Corrective/Preventative 20 Actions (see page 5). 2l a. Is MDEQ expected to take any enforcement action in regards to the 22 MATS compliance issue? Dempsey, Di Avista P. 6 I A. Yes. Due to the failure to meet the MATS standard, Colstrip Units #3 and 2 #4 are now subject to potential MDEQ enforcement action. The extent of this action, 3 including any potential fines, is currently in the discussion phases. 4 a. Please describe the actions the plant owners are taking to prevent a 5 future outage of a similar nature. 6 A. Talen is currently working with MDEQ on an agreement for future MATS 7 compliance assurance. Scrubber balancing plates have been installed to balance flow in 8 the scrubber vessels. Quartz PM test filters are now use in place of the fiberglass filters 9 that had been found to be more reactive with SO. Furnace controls have been improved to 10 optimize PM as well as NOx and slagging. Soot blowers have been reinstalled to have 11 greater control over combustion conditions. 12 a. What was the availability factor for Colstrip Unit #3 and #4, combined, 13 for 2018? 14 A. The equivalent availability factor for 2018 for the Colstrip plant (Units #3 15 and#4) was 82%o. 16 a. In your opinion, was the Colstrip outage a result of imprudent actions 17 on the part of Avista, the Plant Operator, or other Plant Owners? l8 A. No. The outage was not the result of imprudent actions on the part of Avista, 19 Talen, or the other plant owners. In my view, Talen acted appropriately both in terms of 20 conducting the required compliance testing which provided the preliminary findings of 2I non-compliance with MATS, properly notifying MDEQ of the issue and securing an 22 agreement to provide for the limited operation of the units until the issue could be resolved. 23 Talen immediately began troubleshooting to determine the cause of the exceedance, made Dempsey, Di Avista P. 7 1 adjustments and needed equipment improvements which ultimately brought Units #3 and 2 #4backinto MATS compliance. 3 In addition, Talen was very transparent in communicating their status and actions 4 on a daily conference call with all internal stakeholders. Company representatives from 5 Avista and other owners were also periodically on-site during the event to aid in the 6 evaluation and confirm the progress toward compliance. 7 III. COYOTE SPRINGS II 8 Q. Please describe Avista's Coyote Springs 2 ("CS2") natural gas 9 generating facility. 10 A. CS2 is a natural-gas fired combined cycle combustion turbine located in 1l Boardman, Oregon. Portland General Electric, who owns Coyote Springs 1, operates both 12 units. The plant, completed in 2003, has a maximum capacity of 317.5 megawatts in the 13 winter, 285 megawatts in the summer, and has a nameplate rating of 287.3 megawatts. In 14 2016 the plant was upgraded with new control technology that increased its capacity by 18 l5 megawatts. 16 a. During normal operations, how many transformers are in service at 17 CS2? 18 A. There is one Generator Step-Up (GSU) Transformer in use at any time at 19 Coyote Springs 2. This Transformer is fed by one natural gas turbine generator which 20 produces I 8,000 volts of electricity and one steam turbine generator which produces I 3,800 2l volts of electricity. The electricity produced from both units flow through the GSU 22 Transformer where the voltage is increased to over 500,000 volts, and then connects to the 23 Bonneville Power Administration transmission system. Transformer #3 was placed in Dempsey, Di Avista P. 8 1 service in May 2007, and was still in operation as of September 21,2018. Transformer #4 2 was located at the plant for use as a spare, so it was not in use. 3 The CS2 GSU transforners are each filled with 23,696 gallons of mineral oil that 4 is used for the insulation and cooling of electrical components inside the transformer. The 5 GSU transformers have a conservator tank that is slightly elevated and separate from the 6 transformer that acts as a reservoir for transformer oil and allows for adequate space for 7 expansion of transformer oil when heated under increased load or ambient temperature. 8 Q. As it relates to CS2 GSU Transformer #3, what transpired on 9 September 21,2018? l0 A. At2:21PM on September 21,2018, the CS2 GSU transformer (T#3) was 1l tripped by a Buchholz relay action and was automatically removed from service, causing 12 all electrical generation from CS2 to immediately stop. A Buchholzrelay trips when a high 13 energy internal arc is accompanied by the generation of gas in the mineral oil, combined 14 with a surge of oil from the transformer tank to the conservator. The tripping signal stops 15 the flow of electricity from the transformer to prevent further damage to the transformer, 16 to other equipment, or to nearby personnel. 17 Within the next four hours, the online oil analyzer on Transformer #3 confirmed the 18 presence ofacetylene and an increase ofother gasses indicative ofa high energy internal 19 arc. A manual oil sample was taken and sent to the laboratory for analysis; the laboratory 20 conclusion was the same as what the online gas analyzer indicated - namely, that the 2l increase in the amount of gases in the oil resulted in a high energy intemal arc. 22 a. What actions were initially taken to determine the condition of 23 Transformer #3? Dempsey, Di Avista P. 9 1 A. Avista engineering, electrical crews, and protection and control technicians 2 immediately mobilized to conduct further analysis and planning of next steps. These steps 3 included, but were not limited to: 4 5 6 7 8 9 l0 l1 t2 l3 a A review of the online gas-in-oil analyzer readings that suggested a high energy intemal arc. An inspection of the Buchholz relay was conducted to ensure it functioned properly and was not simply a false relay action. An Avista electrical crew performed initial electrical testing and verified the amount of gas in the transformer oil. a. Had the Company undertaken preventative measures or inspections of GSU Transformer #3? A. Yes. Tests and inspections were conducted in May of 2018, where Avista electrical crews performed various tests to check the condition of the transformer. These included testing of the insulation within the transforner as well as external inspections.. All tests concluded with normal results, meaning there were no abnormalities. In addition, Avista uses an online gas analyzer on many of its critical transformers, including CS2, to be able to monitor for dissolved gasses in the oil caused by a high energy internal arc as well as other conditions. Manual oil samples are also separately taken and sent to a laboratory for gas-in-oil analysis on a 3 - 4 month interval. a. Could the Company simply have left Transformer #3 in service, and continue to have the ability to generate at full capacity? A. No. The decision to replace Transformer #3 was thoroughly analyzed by Avista engineering. The following risks were analyzed as part of the decision to replace: . Doble Sweep Frequency Response Analysis (electrical testing) confirmed a notable difference of one of the Transformer #3 internal windings; Dempsey, Di Avista P. l0 o t4 l5 t6 t7 18 t9 20 2l )) 23 24 25 26 27 28 29 a I 2 J 4 5 6 7 8 9 10 11 12 13 o Persistent overheating of the GSU Transformer #3 tank lid that caused Siemens (the original equipment manufacturer) to recommend replacing with a different top; Without repairs, re-energizing would risk catastrophic failure; or if Transformer #3 was placed back in service and failed during peak months (peak electrical need is during the coldest part of the winter or hottest part of the summer) replacement would be more costly; The Buchholz Relay, Serveron on-line gas analyzer, manual oil sampling sent to an external lab, and Kelman, a portable oil analysis tool, were four independent methods or tools that led to the same conclusion that indicated a high energy intemal arc and increased gas-in-oil. o 14 Had the Company not taken Transformer #3 out of service, there was a significant risk of 15 catastrophic failure of not only Transformer #3 but also the potential to damage other 16 nearby equipment and people. Safety of the employees working in proximity of the GSU 17 transformer was a paramount concern. 18 a. Has the Company employed experts or representatives of the 19 transformer manufacturer in order to assist in determining what happened with 20 Transformer #3? 2l A. Yes. VPF Transformer Consulting Services, North American Substation 22 Services, Doble Engineering, and Siemens (the Original Equipment Manufacturer), were 23 among the experts retained to help identify the condition of Transformer #3. 24 a. Without Transformer #3, what is the impact to the overall generation 25 production potential at CS2? 26 A. Without a GSU in service, CS2 has no ability for electrical generation and 27 transmission. Transformer #3 was the GSU in service. When it failed, the decision was 28 made to keep it out of service because of its condition. 29 a. Does the Company maintain a backup transformer at CS2? Dempsey, Di Avista P. 1l a I A. Yes. Since there is a very long lead time to build a similar transformer, the 2 Company has maintained a backup transformer that is located at the facility for any event 3 which may take the current transformer (in this case Transformer #3) out of service. 4 Transformer #4, a virtually exact duplicate of Transformer #3, was purchased from 5 Siemens Brazil and transported to CS2 in 2009. Once on-site, all associated apparatuses, 6 oil coolers, fans, bushings and conservator were installed and Transformer #4 was filled 7 with mineral oil to be kept in a safe, long term storage condition. 8 Q. When did the Company put Transformer #4,the backup transformer, 9 into service? l0 A. Following the analysis of all the testing and indications that pointed to the 1l decision to remove T#3 from service, work began the end of September 2018 to remove 12 Transformer #3 and position Transformer #4 for commissioning. Transformer #4 was 13 placed in service on October 28,2018. While Transformer #4 was in the process of being 14 prepared to move for use, an internal inspection found that supports of some of the electrical 15 equipment were broken. Prior to refilling Transformer #4 with oil, these broken supports 16 were removed and the similar supports were taken out of Transformer #3 and placed in 17 Transformer #4. There were no other concerns found during the remainder of the internal 18 inspection and electrical testing of Transformer #4. 19 a. Did the Company encounter any other issues with Transformer #4 once 20 it was placed into service? 2l A. Initially, no. Following commissioning and returning to unrestricted 22 service, Transformer #4 showed no issues. The Serveron online gas-in-oil analyzer and 23 manual oil samples indicated Transformer #4 was functioning as designed, and oil and 24 winding temperature gauges mounted on the transformer were within the normal, expected Dempsey, Di Avista P. 12 I range. 2 a. Will you please provide more detail as to the nature of the issues later 3 found with Transformer #4? 4 A. Yes. All transfonners will generate gas-in-oil; Transformer #4 is no 5 different. There were multiple gasses present and the amount of gas in the oil was slowly 6 increasing, as shown by the on-line oil analyzer. This is not traditionally unexpected. 7 However, on November 20,2018, the oil analyzer gave the first indication that there may 8 be an issue with Transformer #4. A sharp increase in combustible gasses in the oil 9 suggested an elevated metal temperature internal to the transformer. A manual oil sample 10 was taken and sent for off-site analysis, and similar results were observed. 1l Immediate steps were taken in an attempt to reduce the increasing gas and to lower 12 the risk of further damage. CS2 was de-rated, in order to limit the amount of electricity 13 being produced and flowing through the transformer, to 280 MW, in an attempt to stop the 14 increasing gas in the oil by reducing the amount of heat generated in Transformer #4. After 15 a few days it was further de-rated to 200 MW. These actions of de-rate did not resolve the 16 gas-in-oil issue. Transformer #4 was removed from service for electrical and internal 17 inspection on December 8, 2018. The electrical testing and the visual intemal inspection 18 performed by experts from North American Substation Services, did not point to any high 19 energy arc locations within Transformer #4. 20 a. Given the issues with Transformer #4, is it still in operation? 2l A. Yes. Transformer #4 was placed back in service after the testing and 22 inspection. All of the test results and reports have been shared with Siemens and VPF 23 Transformer Consulting Services for their recommendation for continued operation. The 24 recommendations were to place Transformer #4 back on line at a de-rate level, beginning Dempsey, Di Avista P. 13 1 at 200 MW, and monitor the gas-in-oiI and transformer temperatures while operating. 2 Since the start-up in December, the amount of increase of the gas-in-oil has allowed the de- 3 rate to be lessened and the available capacity to be restored to 280 MW. Avista will 4 continue to arralyze for further de-rate adjustments as the amount of the gas-in- oil allows. 5 Q. Are you continuing to monitor and test Transformer #4 so as to keep it 6 in service while next steps are being determined for Transformer #3? 7 A. Yes. Our main analysis tools continue to monitor the gas that is being 8 produced in the mineral oil of the transformer, and to monitor the winding and oil 9 temperatures of the transformer. The gas-in-oil analyzer located on Transformer #4 10 samples the oil every 2 to 4 hours. Additionally there are manual oil samples taken each 11 week and sent a laboratory for a third party analysis. This helps us forecast when action 12 should be taken to ensure our transformer oil retains sufficient insulating and cooling 13 qualities. 14 O. As it relates to Transformer #3, what is the current status of either 15 fixing or replacing that transformer? 16 A. Transformer #3 is currently being prepared for shipment to an ABB facility 17 in Ontario, Canada. Once it arrives in those facilities it will be disassembled in order to 18 identify the failure location. Avista does not yet know the final course of action for 19 Transformer 3 as this depends on what we find as well as where we find ourselves over the 20 next year or two with respect to Transformer 4. The current plan is to change the plant 2l configurationto accommodate single-phasedual-woundtransformers. 22 a. Given the issues with Transformer #4, what are the next steps, if any, 23 to alleviate the problem with that transformer? Dempsey, Di Avista P. 14 1 A. Avista's internal engineering, along with transforner consultants, continue 2 to monitor the gas-in-oil to ensure the insulating and cooling qualities of the oil remain 3 sufficient. Should the gas increase to a point where it is no longer safe to operate, we plan 4 on taking CS2 and the transformer off-line and running the transformer oil through a 5 degassification process. This will reduce the gas-in-oil back to a point where the insulating 6 and cooling characteristics are acceptable, and dissolved combustible gasses are at a safe 7 level. We completed one such plan on degassifying process during our recent May 2019 8 planned maintenance outage. 9 Once Transformer #3 has been repaired or replaced, the timing for swapping it with 10 Transformer #4 will be developed. At that time, Transformer #4 will be removed from 11 service and we will conduct further analysis of the gassing issue. 12 a. As the Manager of Thermal Operations and Maintenance, do you 13 believe that the actions of the Company in any way contributed to the issues with the 14 two transformers at CS2? 15 A. No, I do not. As you can well imagine, the electrical system is extremely 16 complex. We use large machines and devices in order to generate and deliver the energy 17 our customers require. Unfortunately, machines do break down, and that includes 18 transformers. In my view, there was no additional level of maintenance or capital additions 19 that could have prevented the issues with either Transformer #3 or #4. The Company 20 utilized industry standards for monitoring and analyzing gas in the transformer oil, and 2l operated CS2 within the transformer (s) rated capabilities. The Company also performed 22 electrical testing in the Spring of 2018 on Transformer #3 to verify its condition remained 23 sufficient to remain on line and handle the full generation of CS2. Dempsey, Di Avista P. 15 1 2 a. A. Does this conclude your testimony? Yes, it does. Dempsey, Di Avista P. 16