20190730Dempsey Direct.pdf

DAVID 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: [phone], FAX: [phone]
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
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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.
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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?
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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.
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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
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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
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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?
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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
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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
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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?
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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:
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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;
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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.
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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?
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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
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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
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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?
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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.
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A.
Does this conclude your testimony?
Yes, it does.
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