Berkshire Hathaway Energy

Alert # 1

Table of Contents

Custom Website for Berkshire Hathaway Power Generation Plants

PacifiCorp NO_x Project is just One Step along the Way to the New Decision Making Approach

Huntington Power Plant of PacifiCorp has been sued for Water Contamination

Coalstrip Owners including PacifiCorp agree to stop discharging Scrubber Wastewater

Wyodak replaces ACC and selects Pall Filters

PacifiCorp plans unveiled in 2014 Analysis

Energy-saving Projects at Washington Plants

Chemicals used PacifiCorp Wyoming plants are identified

PacifiCorp Activities to Receive Special Coverage in GTRE Decisions

GE Provided Op Flex Optimization Software at PacifiCorp Currant Creek for $7.8 million. What was the payback?

Currant Creek Plant is CHP with Successful Tomato Growing Operation

Energy Saving Projects at Washington Plants

Approved gas turbine component supplier list for PacifiCorp

Custom Website for Berkshire Hathaway power generation plants.

The power industry has been challenged to progress at the “hurry up” pace endemic to Silicon Valley. One of the cited routes is the utilization of the interconnectivity among machines. However, this progress requires better interconnectivity of people. McIlvaine has introduced a free internet decision system for power plants based around separate websites for gas turbines/reciprocating engines and coal fired power.

The value of this system to a power plant has been demonstrated at PacifiCorp where use of the system along with a series of five webinars has shown the way to lower cost NO_x control for four coal fired units. The decisive classification tools in the system were important but the insights from the “wise crowd” have been equally important. McIlvaine is now taking the next step in interconnectivity with a website and decision system for all the Berkshire Hathaway generation plants.

The website includes links to the decision systems but also includes an Alert just for BH people. It includes details on each generating unit with continuing updates. McIlvaine already tracks components and consumables such as the NO_x reagents and suppliers for the various gas turbine units.  The coal plant NO_x project will use more reagent than any of the gas turbine plants.  The combination of H₂0₂ and urea may be better than just urea.  If this is true for the coal plants is there a benefit for the gas turbine plants?

Siemens, GE and Emerson are each proposing optimization systems for the coal NO_x project. The gas turbine plants in the fleet are newer and the operators have insights on the latest technology.  One upgrade was priced at $8 million if the improved performance was achieved but only $300,000 if it was not. The decision makers for the coal project need to hear from the gas turbine plant operators on this.

String wound condensate polishing filters for one of the coal plants were replaced several years ago with 20 micron filters. However, at the time there was speculation that the more expensive 10 micron filters would have been worth the extra investment.  A total lowest cost of ownership study on this selection would be useful to all the coal and combined cycle gas plants.  The bidders list for Currant Creek lists Cuno as the only approved bidder. The Cuno string wound filters were deemed too inefficient and that is why they were replaced with Pall 20 micron filters at the coal plant.  But the condensate cooling at that plant is achieved with air cooled condensers.  This results in more contamination than when wet cooling is utilized.  Also Cuno has a range of filters. So an approved bidders list should specify filter efficiency and take advantage of recent experience.   In any case a condensate filter users group within the corporation would be desirable.

Valve and pump approved bidders’ lists for the water and steam applications for one new gas turbine plant are included in the decision system. In its valve and pump services McIlvaine is writing about the many improvements in the product offerings.  This includes designs but also materials such as hard facings. This list should be shared among all the plants and the “wise crowd” invited to provide insights. There should be a BH power generation valve users group and also a users group on pumps.

There are lots of individuals in the crowd who can provide valuable input on the generation mix.  Warren Buffet has been defending the policy of not subsidizing photovoltaic solar owners in Nevada. They are paid 11 cents/kWh for their electricity when the company can buy from central solar suppliers for 5 cents/kWh.  At the heart of this dispute is the true cost of generation when transmission and other costs are included. This true cost is influenced by the fluctuations in demand and the contribution of all the other generation sources in the system. Mid American Energy filed changes to its private generation tariff with the Iowa Utilities Board. It is now dedicated to 100 percent renewables over time.  Wind energy will be the foundation.  Relative to the solar tariff the company said “Most private solar customers remain connected to the power grid for back-up power to use when the sun isn’t shining. However, they pay less for using the grid – customers who don’t have private solar end up paying the difference. We believe the filing is a step forward in the process to balance the needs of all customers and ensure that customers who install private generation pay their share of the costs for maintaining the grid. We will continue to move policies in a direction that encourage private solar and wind development.”

There is a commercial tomato greenhouse at the Currant Creek plant.  It produces 22 million lbs of tomatoes per year.  It uses heat and CO₂ from the power generator but also is recovering a significant amount of water from the flue gas (derived from hydrogen in the fuel).  The grower operates another plant in California and is building one in Canada.  These plants each use two 4 MW gas engines to provide the electricity, heat, light, and CO₂.  Their energy efficiency is greater than 80 percent.  However, the produce grows up to 40 percent faster because of the CO₂. Therefore you can make a good case that the gas engines are more than 100 percent efficient and therefore are better than wind or solar.  This case is even stronger when the grower uses biogas from the produce waste to fuel the engines. The recovery of water from the exhaust at Currant Creek creates another ponder able. McIlvaine has a common metric to measure the harm from CO₂ vs. the recovery of water in an arid area.  10 tons of recovered water is worth 1 ton of CO₂.  Therefore further quantification of the water recovery is important.

Much of the area in which the Berkshire plants are located is arid and sunny.  Many experts are predicting a huge future for indoor agriculture with gas engines burning low cost natural gas or biogas. These engines will operate 24-7 unlike wind and solar. Data centers are investing in emergency engines to provide up to 6 percent of all the energy potentially consumed in the region.  They could invest in NO_x control equipment and switch to standby service. Should gas engines be a bigger part of the fleet? Presently the long range plans for PacifiCorp only include a fractional percent of energy from this source.

The “wise crowd” of Berkshire people along with experts from the supplier and consulting companies will have a unique tool to help make better combustion, flow control and treatment decisions throughout the organization.  The long range plan is to provide the custom websites for all the major utility generators throughout the world. Since these are offered free of charge the challenge is not obtaining the utility buy in but in the funding from the supplier community who will benefit from the customer interface and the mechanism to demonstrate that their products will result in the lowest total cost of ownership (TCO).

PacifiCorp NO_x Project is just One Step along the Way to the New Decision Making Approach

Five webinars have been conducted for PacifiCorp to help them with their decisions on NO_x removal at four units installed at Hunter & Huntington.  It looks as though the solution will involve:

•         Combustion modifications

•         Optimization

•         SNCR with urea or urea and H₂O₂

•         In duct SCR

•         Ozone /H₂O₂ injection prior to the scrubber

Ian Andrews of PacifiCorp believes that the series of five webinars have set the stage for a number of individual discussions with vendors and for selection of technologies to test at a 5 MW test facility.

The in-duct SCR and the optimization options have been reviewed with multiple vendors in the webinars and PacifiCorp is pursuing discussions with individual vendors. It is very likely that a test facility will be set up to test the ozone injection ahead of the scrubber.

A deeper dive into wastewater ramifications of NO_x reagents uncovered concerns about SO₂ removal in a lime-based system. H₂O₂ is being proposed for PacifiCorp. It could be added along with urea in the boiler for NO_x reduction. It is being proposed along with ozone to oxidize NO_x ahead of the scrubber. Both processes may generate unreacted NO₂.  This unreacted NO₂ apparently can reduce sulfite ions and lower SO₂ capture. 

Solutions include adding additional chemicals in the scrubber. Dibasic acid (DBA) is used with some limestone systems and does raise pH. Adding dolomite (magnesium lime) is another potential solution. On the other hand, it would seem that the NO₂ will be converted to N₂O₅ with ozone injection. The N₂O₅ may also affect SO₂ capture and therefore dictate some chemical to raise pH.

Marsulex supplied the scrubber, Graymont supplies the lime. AECOM is the licensee for the ozone injection system designed by Linde.  PeroxyChem, Solvay, and U.S. Peroxide offer the H₂O₂. Invista offers DBA.  Nalco, GE Betz and Solenis are all involved with chemical additions in the boiler and for wastewater treatment. They may have insights. McIlvaine encourages input from these companies and others who can contribute to this analysis.

There is a concern regarding a visible plume which can be created from H₂O₂ additions. The three peroxide suppliers can adequately address this question.

There were a number of valuable discussions that are more applicable to other plants than to Hunter and Huntington. The air pre-heater is affected by whichever NO_x control option is selected. The potential for ABS fouling can be reduced by sorbent injection ahead of the air heater. If catalytic filters are selected, there would be major air heater changes. Catalytic baskets, according to Arvos are not an attractive option because of the need to periodically wash the air heater internals.

The present discharge temperature from the air heater is 275°F. A Hamon baghouse with low pressure high volume cleaning is installed at each of the four units. F.L Smidth has a catalytic filter bag which can operate at 400°F at high efficiency but at 275°F it would have low efficiency and there would be concern about ABS plugging. Hamon is investigating a new catalytic bag design which would operate efficiently at the 275°F temperature. However, this is still in R&D development.  Hamon has offered to supply a pilot unit to determine the efficacy of this option.

Because PacifiCorp already has downstream scrubbers, the dry sorbent injection (DSI) combined with catalytic filtration is not attractive. However, a catalytic filter with 33 foot long bags operating at 400°F is now operating successfully at a European cement plant. This opens the door for several combinations of technologies.

One option includes a two-stage heat recovery system (similar to a HRSG). The rotary air pre- heater reduces the temperature to 450°F. The fiberglass catalytic filter baghouse with DSI removes the particulate, mercury and acid gases while reducing the NO_x. A second heat exchanger extracts the heat from the clean hot gas and discharges flue gas at 150°F. The capital cost of this system would be much lower than the separate SCR, baghouse, and wet scrubber combination.

Another option for new plants is to use ceramic elements at 850°F for DSI and catalytic filtration. A new air heater design, taking advantage of the clean gas condition, would be more efficient and would eliminate in-leakage which is typically 10 percent. Flue gas would be discharged at 150°F. The ID fans would utilize less energy due to the lower gas volume. The problem with this approach is that mercury removal is not going to be high due to the 850°F injection temperature. W.L. Gore is installing their mercury removal module down stream of scrubbers and could insert their module in the exhaust duct after the heat exchange.

The PacifiCorp NO_x project demonstration is being expanded to other subjects and other companies.

Huntington Power Plant of PacifiCorp has been sued for Water Contamination

A coalition of environmental groups launched a lawsuit against PacifiCorp over coal ash disposal practices at Rocky Mountain Power's Huntington power plant, asserting liquid and solid wastes are contaminating surface water and groundwater.

The suit filed in U.S. District Court for Utah asks that PacifiCorp be forced to prevent further contamination of Huntington Creek and surrounding areas by capping the waste, preventing groundwater from reaching Huntington Creek and restoring the stream to its natural state.

Rocky Mountain Power, which is a unit of PacifiCorp, and the Sierra Club, HEAL Utah and Public Justice have been in talks for a couple of months over the disposal methods for coal ash — a byproduct of coal combustion — but the groups could not come to any resolution.

Dave Eskelsen, a spokesman for Rocky Mountain Power, said the lawsuit is baseless and the Huntington power plant is in compliance with environmental regulations and all permits.

"Wastewater is stored in a clay-lined evaporation pond throughout the year and is used to irrigate the Research Pond from April through November. Irrigation water is applied at a rate to minimize surface water runoff and infiltration into groundwater.

The bedrock at the plant site is Mancos Shale, which contains large amounts of soluble salts that leach into ground and surface water. Precipitation falling on the site dissolves more soluble minerals from the Mancos Shale the longer it has been in contact with the formation. As a result groundwater quality varies considerably making it difficult or impossible to distinguish between naturally-occurring changes in water quality from changes due to activities and facilities related to the power plant.

Ground water in the alluvial aquifer under the Research Farm is of limited extent and generally poor quality, except in wells adjacent to Huntington Creek. Monitoring data since the late 1970s shows that land applications of wastewater has not significantly affected ground water quality. A new set of ground water monitor wells was installed in 1997 and has been sampled semi-annually since then. By design, protection levels are a fraction of the ground water quality standard to provide an early warning of impending ground water contamination and if necessary, implement corrective actions.

To evaluate whether PacifiCorp’s activities are affecting water quality in Huntington Creek, surface water is sampled in Huntington Creek above and below PacifiCorp’s facilities. Surface water quality standards must be met at the downstream monitoring point.

Eskelsen continued, “These groups probably don’t understand that there has been research conducted at those farms by Utah State University in the utilization of processed water in this way. The irrigation process is closely monitored so the application of water is completely used.”

“We are not in violation of any laws under our federal and state permits,” he concluded.

Coalstrip Owners including PacifiCorp agree to stop discharging Scrubber Wastewater

The owners of the Coalstrip power plant in southeastern Montana signed an agreement in July to stop pouring coal sludge and other liquid waste into storage ponds.

The agreement between Talen Energy, which represents the six Coalstrip owners and three environmental groups, is the latest development for the Coalstrip Steam Electric Station, the second-largest coal-fired power plant west of the Mississippi River that has come under increasing market and regulatory pressure. Earlier this month, the plant’s owners agreed to shut down its two older units by 2022 in a proposed settlement filed in a separate lawsuit.

The new settlement calls for Coalstrip’s two newer units to convert to a non-liquid disposal system for its bottom ash by 2018 and for its scrubber sludge by 2022. Bottom ash is sluiced with water and disposed of in the ash ponds outside the plant, The other types of liquids that go to the ponds include scrubber sludge. 

Under the agreement, the Coalstrip owners will convert to a “non-liquid” disposal system for CCR material generated by Coalstrip Units 3 and 4’s scrubbers, which is deposited in the effluent holding ponds for Units 3 and 4 (the “Units 3 and 4 EHP”),  no later than July 1, 2022.

Wyodak replaces ACC and selects Pall Filters

This coal-fired power plant used air cooled condensers which caused problems with the condensate.  In 2011 PacifiCorp purchased Pall 20 micron filters for the full flow. The question posed at the time was whether it would be worthwhile to use more efficient filters e.g. 10 micron or 6 micron.  Five years have now passed since this presentation at the 2011 ACC users group. What is the current status and experience?

This 365 MW coal-fired power plant in Gillette, Wyoming operates with a 1,800 psi throttle pressure. The fuel is Pulverized Powder River Basin Coal.

The original ACC was GEA and replaced in 2011 with an SPX design. Joy Niro dry scrubbers and Hamon fabric filters are installed. B&W provided a low NO_x burner upgrade in 2011.The steam turbine was supplied by GE.

Gary Hoffman – PacifiCorp and Pat Caton – AEC Power Flow presented information on their selection of a filter for full flow condensate filtration at the 3rd Air-Cooled Condenser User Group Meeting on September 20, 2011

In 2011 after 33 years of service, the air-cooled condenser was replaced. High turbine back-pressure due to severe in-leakage provided adequate justification for replacement. (18,000+ MW/hr. lost in 2010 due to high ambient temperatures).

Before Replacement:

-          Air in-leakage pegs the meter (> 30 scfm)

-          Always running with both air ejectors in service

-          Condensate pump discharge dissolved oxygen often > 200 ppb, almost always > 100 ppb

After Replacement:

-          Air in-leakage @ 9 scfm with one ejector in service

• (Note: steam duct from LP turbine to the ACC was not replaced with the ACC. Several expansion joints on the line supplying the ACC are likely leaking)

-          Condensate pump discharge dissolved oxygen most always less than 100 ppb and often less than 40 ppb – still a major concern!

Experience at Currant Creek plant (Mona, UT) was negative relative to string wound filters.

-          178 string-wound Cuno filters

-          In service for 1 year with no real increase in pressure drop. This suggests significant bypassing with string-wound filter.

-           Filters always in service

-          1,000 ppm chromium on filtrate analysis

-          Normal air in-leakage at 30 acfm

So the decision was to choose a high efficiency filter. Pall high flow filters were selected.

Vessel design code: ASME VIII DIV 1 “U” STAMP

– Flow rate: 5,500 gpm

– Operating pressure: 450 psig

– Filtration: Beta X(c) = 5,000

– Calculated clean element pressure drop: 0.608 psig

– Calculated vessel pressure drop: < 5 psig

– Bypass automatically opens at a pressure drop of 50 psig

– Installed downstream of condensate pump and upstream of 5th point feedwater heater
   (1st LP heater).

Condensate filtration package consists of 1 vessel with 19 pleated filter elements, isolation valves, by-pass piping w/isolation valve, drain valves, DP transmitter and NEMA 4 control panel. All components are mounted on a structural steel frame.

– Vessel inlet and outlet port isolation valves are butterfly valves with a manual handwheel / gearbox operator. These valves are used for positive isolation of the vessel from the condensate system when element changeout is required.
 

– Isolation valve in the by-pass loop is also a butterfly valve with a pneumatic actuated, spring return operator. The operator uses a solenoid valve for pilot control of the main actuator piston. The solenoid valve receives an output signal from a PLC in the control panel, based on an input signal from the differential pressure transmitter.
 

– The by-pass loop is included to provide uninterrupted flow when elements need to be changed. By-pass loop can handle full system flow. No operator intervention is required to move into the by-pass mode. At Wyodak, the switchover to bypass mode happens at 50 psid across the filter. Local alarming is available to alert operations of the need to change filters.

The conclusions were that:

–        Filter installation has been very effective at removing suspended iron.

–        Additional testing is recommended to quantify current iron transport.

–        Better removal is available with 10μ or 6μ filter; however, the cost of element replacement suggests using 20μ elements

This system has now been operating for five years. What is the latest experience? Are the 20 micron rated filters still considered to be the best economic choice?

PacifiCorp plans unveiled in 2014 Analysis

A number of Pacific plants need to install SCR. The 2014 plan lists specific timetables. Litigation has changed some of these plans in the interim and we need to determine the latest status but this has the information in one place and is a valuable reference. You will find the full text in the PPAQD Decisions intelligence System.

The Environmental Protection Agency (EPA) partially approved and partially rejected the Wyoming Regional Haze state implementation plan (SIP) and issued a federal implementation plan (FIP) to cover those areas of SIP disapproval in January 2014. This action established compliance requirements and schedules for specific Wyoming coal units under the Regional Haze program, including a requirement for installation of selective catalytic reduction (SCR) at Wyodak by early March 2019.

In March 2011, the state of Arizona submitted its Regional Haze state implementation plan (SIP) to the Environmental Protection Agency (EPA) for review. The SIP requires currently installed low NO_x burners (LNB) as best available retrofit technology (BART) for NO_x emissions at Cholla Unit 4. By final rule dated December 5, 2012, EPA disapproved portions of the Arizona Regional Haze SIP and issued a federal implementation plan (FIP). The FIP requires, among other things, installation of selective catalytic reduction (SCR) on Cholla Unit 4 by January 4, 2018. The FIP also institutes an averaged NO_x emissions rate of 0.055 lb/MMBtu for Cholla Units 2, 3 and 4. In January and February 2013, PacifiCorp, the state of Arizona and other Arizona utilities filed separate appeals of EPA’s FIP with the U.S. Ninth Circuit Court of Appeals.

Ultimately, EPA’s final determination requires installation of the following NO_x and PM controls at PacifiCorp facilities:

SCR equipment and a baghouse at Naughton Unit 3 by December 31, 2014; SCR equipment at Jim Bridger Unit 3 by December 31, 2015; SCR equipment at Jim Bridger Unit 4 by December 31, 2016; SCR equipment at Jim Bridger Unit 1 by December 31, 2022; SCR equipment at Jim Bridger Unit 2 by December 31, 2021; SCR within five years or a commitment to shut down in 2027 at Dave Johnston Unit 3; and SCR at Wyodak within 5 years. With respect to Naughton Unit 3, EPA indicated its support for the conversion of the unit to natural gas and that it would expedite action relative to consideration of the gas conversion once the state of Wyoming submitted the requisite SIP amendment. The EPA action became final on March 3, 2014.

Mercury:  The Company believes its emission reduction projects completed to date or currently permitted or planned for installation, including the scrubbers, baghouses and electrostatic precipitators required under other EPA requirements, are consistent with achieving the MATS requirements and will support PacifiCorp’s ability to comply with the final standards for acid gases and non-mercury metallic hazardous air pollutants. PacifiCorp will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the standards.

Energy-saving Projects at Washington Plants

PacifiCorp Energy has seven generation facilities in their fleet that provide electricity to the

State of Washington. These units vary from coal‐fired to natural gas to wind. The State of

Washington has recently passed legislation requiring PacifiCorp to complete all cost effective

energy efficiency measures in these generation facilities.

The purpose of this 2011 report was to outline the systems investigated and detail the cost effective measures at three of the seven locations: Jim Bridger (Unit #1 only), Chehalis and Goodnoe Hills.  This 2011 report is displayed in full in the PPAQD intelligence system.

One of the biggest potential improvements at the time of the report was adding VFD to pumps and fans. For example, VFD could be installed at Jim Bridger for RO feed and condensate pumps. This system consists of three RO system trains; A, B and C. Trains A and B utilize

three 60 HP RO feed pumps and train C has two 75 HP pumps. Trains A and B use a discharge

control valve to deliver about 270 gpm of filtered water to the RO membranes. During normal

operation two of the three trains are in operation. When Trains A and B are in operation only 2

of the three pumps are needed. Train C only needs one of two pumps to operate.

Proposed: RO feed pumps on Trains A and B should be upgraded with VFDs and controls to

vary pump speed to deliver the required flow to the RO membranes. This measure would add the following equipment:

•         Six 60 HP pump VFDs

•         VFD controls

Condensate Pumps Baseline: The condensate pump system consists of three 700 HP 7,200 volt pumps that transport condensate from the discharge of the main turbine to the Deaerator (DA) tank. During normal operation two of the three pumps are needed to maintain the tank level in the DA tank. Two parallel discharge control valves are modulated to the desired DA tank level,

Proposed: The proposed changes would install new inverter rated motors with VFDs and necessary controls to regulate the pump speed. The pump speed will be varied to maintain the

DA tank level. The existing control valves should be fully opened during normal operation.

This measure would add the following equipment:

•         Three 700 HP 7,200 volt pump VFDs

•         Three 700 HP 7,200 volt inverter duty motors

•         VFD controls

Forced Draft Fans Baseline: This system consists of two 2,250 HP 7,200 volt centrifugal fans that operate in parallel to provide secondary and overfire combustion air to the boiler. Capacity control is achieved by variable inlet vanes. The fans maintain a static pressure of approximately 16 in WC in the duct. Both fans are needed during normal operation.

Proposed: The proposed ECM is to install new 7,200 volt inverter duty motors and VFDs with controls. The existing inlet vane dampers should be removed and speed control used to meet the required flow and pressure based on unit load. This measure would add the following equipment:

•         Two 2,250 HP invertor duty 7,200 volt motors

•         Two correctly sized VFDs

•         VFD controls

Other pumps and fans were included. The investments and savings are shown below.

Also included is the analysis for the 520 MW gas turbine combined cycle power plant located in Chehalis.

Chemicals used at PacifiCorp Wyoming plants are identified

A tax dispute resulted in this analysis of chemicals used in the boiler, water treatment, cooling, scrubbers and wastewater at four Wyoming plants. At Jim Bridger and Naughton sodium bicarbonate is used as the scrubbing reagent.  At Dave Johnston and Wyodak limestone is the reagent. Since Wyodak uses an air cooled condenser its chemical usage is less than the other three plants which use evaporative cooling.

PacifiCorp Activities to Receive Special Coverage in GTRE Decisions

McIlvaine has been conducting a series of five webinars for PacifiCorp to help them with their decisions on NO_x control at coal-fired power plants. The webinars are organized around the information which is gathered for Power Plant Air Quality Decisions.  This effort is being expanded to cover activities at all the PacifiCorp power plants. The purpose of adding information on PacifiCorp gas turbine and gas engine activities is to demonstrate the value of GTRE Decisions to any power plant

Person to person communication optimization is just as challenging as machine to machine. Suppliers and consultants as well as individuals within PacifiCorp can benefit from the communication regarding activities at all the plants.  All the newer thermal power plants operated by the company are fueled with natural gas.

GE Provided Op Flex Optimization Software at PacifiCorp Currant Creek for $7.8 million. What was the payback?

An upgrade was supplied several years ago.  We would like to report on the current status and include options by one and all on the approach.

The Currant Creek project is a grassroots 525-megawatt natural gas-fired power plant consisting of a 2 x 1 combined cycle power block. The plant was constructed in two phases: Phase 1 consisted of the installation of two GE 7FA combustion turbine generators to operate in simple cycle mode, and Phase II called for the installation of two heat recovery steam generators (HSRGs) and a steam turbine generator.

The two HRSGs constructed in Phase II were a 10-module tube bundle design. PCL’s work included installation of the Low Pressure (LP), Intermediate Pressure (IP), and High Pressure (HP) steam drums, boiler piping, soot blowers, platforms, grating, and associated equipment.

PacifiCorp entered into a sole source contract with General Electric International to install its Op-Flex cold day performance package on the Currant Creek plant. The estimated amount of this purchase is $7,819,500.

Under the contract General Electric was to provide three equipment packages designed to increase the cold weather performance, gas turbine operational flexibility, increase base load output, and enhance combustion dynamics monitoring at the Currant Creek plant.  The “Op-Flex Cold Day Performance” package is designed to provide increased output and improved heat rate during cold weather conditions.  The “Op-Flex Turndown” package provides the ability for plant turndown (reduction in load) to be reduced from 80% to 70%.  This package will result in lower operating costs, increased low load reliability, less fuel consumption to stay on line, and expanded emission compliance.  The “Continuous Dynamics Monitoring” package enables the first two packages to work.

PacifiCorp said that they had exhausted competitive alternatives to the engine control packages offered by General Electric.  These packages can only be provided by General Electric, the original equipment manufacturer and owner of the proprietary engine control system.  Payment for the equipment packages is based on a sliding scale based on performance.  If the unit performance meets or exceeds the guaranteed performance levels, payment will be at the level stated above.  If unit performance does not meet the guaranteed level, the payment is reduced accordingly down to a minimum level of $319,500.

If you have any contributions to update us on this, it would be appreciated.

Currant Creek Plant is CHP with Successful Tomato Growing Operation

The Currant creek plant provides heat and CO₂ to a large on site tomato greenhouse. It involves a large duct providing waste heat and CO₂ as shown in the picture below.  It has been quite successful but one PacifiCorp source said that in the future the hot water from the HRSG a smaller duct with just enough flow to provide the CO₂ would be an even better solution.

A duct connects Rocky Mountain Power's Currant Creek Plant with the Houweling’s Tomatoes greenhouse. The power plant heats the greenhouse and it provides nutrients and condensed water to the tomato plants.

The 28-acre Houweling’s Tomatoes greenhouse near Mona, Utah, is among the first of its kind in the world to draw its heat and plant-nourishing carbon dioxide from a neighboring power plant. A bonus for Houweling’s is the water it condenses from the flue gas is used to irrigate the tomato plants.

Brad Richards, manager at Rocky Mountain Power’s Currant Creek Plant explained, “The manufacturer of the boiler and stack engineered the penetration in the stack and determined there wouldn’t be any issues with our operations or with our emissions monitoring equipment.”

A plant outage was required to complete construction of the duct. So Houwelings and Rocky Mountain Power coordinated the work during planned maintenance on a weekend in April 2015.

The Houweling’s Tomatoes heat recovery system inside its boiler building connects to the 10-foot-diameter duct from Currant Creek Plant.

“We’ve been upfront with Houweling’s from the beginning that our customers are first priority with everything having to do with safety and plant operations,” said Ian Andrews, Rocky Mountain Power resource development director. “We had to coordinate a phased construction process to work around the plant’s planned outage schedule.”

Houweling’s began construction of the 475-foot-long duct from the plant to the greenhouse in July 2015. The 10-foot-diameter duct stands 25 to 30 feet above the ground.

“We didn’t expect any effects on plant performance or reliability, and there haven’t been any,” Richards reported. “The system is working well and was designed with very few changes to our normal operation.”

Using an Argus control system, waste exhaust is drawn off the side of the stack, diverting it into Houwelings energy building where thermal energy is captured and stored for on-demand heat. Condensation from this process is captured and used to supplement irrigation water, and the remaining exhaust CO₂ is released directly into the greenhouse to promote plant growth. The custom Argus system controls the equipment that extracts the CO₂ and the heat from the stack gas and sends signals to and from the power plant, including general status, alarm points and portions of dampers, CO₂ demand, boiler status, and temperature and efficiency readings. The control system also monitors gas flow and temperature, concentration of CO and NOx, and controls the condenser fans, condenser pumps and dampers on this project.

Yurij Duda, Argus Controls General Manager congratulated Houweling’s on the award: “Houwelings is a real leader in sustainable agriculture and is truly committed to innovation in energy management. Argus was honored to be selected as their control system partner to help make this unique project a reality.”

Energy Saving Projects at Washington Plants

PacifiCorp Energy has seven generation facilities in their fleet that provide electricity to the

State of Washington. These units vary from coal‐fired to natural gas to wind. The State of

Washington has recently passed legislation requiring PacifiCorp to complete all cost effective

energy efficiency measures in these generation facilities.

The purpose of a 2011 report was to outline the systems investigated and detail the cost effective measures at three of the seven locations: Jim Bridger (Unit #1 only), Chehalis and Goodnoe Hills.  This 2011 report is displayed in full in the PPAQD Intelligence System.

One of the biggest potential improvements at the time of the report was adding VFD to pumps and fans. For example, VFD could be installed at Jim Bridger for RO feed and condensate pumps.

This system consists of three RO system trains; A, B and C. Trains A and B utilize

three 60 HP RO feed pumps and train C has two 75 HP pumps. Trains A and B use a discharge

control valve to deliver about 270 gpm of filtered water to the RO membranes. During normal

operation two of the three trains are in operation. When Trains A and B are in operation only 2

of the three pumps are needed. Train C only needs one of two pumps to operate.

Proposed: RO feed pumps on Trains A and B should be upgraded with VFDs and controls to

vary pump speed to deliver the required flow to the RO membranes.

This measure would add the following equipment:

·         Six 60 HP pump VFDs

·         VFD controls

Condensate Pumps Baseline: The condensate pump system consists of three 700 HP 7,200 volt pumps that transport condensate from the discharge of the main turbine to the Deaerator (DA) tank.

During normal operation two of the three pumps are needed to maintain the tank level in the

DA tank. Two parallel discharge control valves are modulated to the desired DA tank level.

Proposed: The proposed changes would install new inverter rated motors with VFDs and

necessary controls to regulate the pump speed. The pump speed will be varied to maintain the

DA tank level. The existing control valves should be fully opened during normal operation.

This measure would add the following equipment:

·         Three 700 HP 7,200 volt pump VFDs

·         Three 700 HP 7,200 volt inverter duty motors

·         VFD controls

Forced Draft Fans Baseline: This system consists of two 2,250 HP 7,200 volt centrifugal fans that operate in parallel to provide secondary and overfire combustion air to the boiler. Capacity control is achieved by variable inlet vanes. The fans maintain a static pressure of approximately 16 in WC in the duct. Both fans are needed during normal operation.

Proposed: The proposed ECM is to install new 7,200 volt inverter duty motors and VFDs with controls. The existing inlet vane dampers should be removed and speed control used to meet the required flow and pressure based on unit load. This measure would add the following equipment:

·         Two 2,250 HP invertor duty 7,200 volt motors

·         Two correctly sized VFDs

·         VFD controls

Other pumps and fans were included.  Also included is the analysis for the 520 MW gas turbine combined cycle plant located in Chehalis.

Approved gas turbine component supplier list for PacifiCorp

Preferred vendors based on the Currant Creek 2 plant are designated. For example, Cuno is the approved supplier for the condensate filters. However, in 2011 at Wyodak the Pall filter was installed to replace the existing Cuno string wound filters and positive results such as less iron deposition were experienced. Has this information been transferred to those making up bidders’ lists?