AltaGas pursues major revamp for 553-MW Blythe II gas-fired project in California

AltaGas Sonoran Energy, which last year acquired the long-planned and yet unbuilt Blythe Energy Project Phase II, applied Aug. 7 at the California Energy Commission for a major revamp of that gas-fired project, adding that the new name for the facility will be the Sonoran Energy Project.

“Since acquiring the Project in May 2014, AltaGas Sonoran has worked diligently with its consultants and engineers to develop modifications to the Project’s design in an effort to construct a least cost, best fit project while taking into account the current energy market and environmental conditions,” said the application. “As a result, AltaGas Sonoran has determined that changes to the Project design are needed to best support integration of renewables to the grid and provide fast-starting, combined cycle generation that will increase electrical efficiency of the Project.”

AltaGas Sonoran is an affiliate of AltaGas Ltd., a Canadian corporation and a diverse energy infrastructure company with natural gas, electric power, and natural gas utility assets located in Canada and the United States.

AltaGas Sonoran said it seeks these changes to the Blythe Energy Project Phase II license:

  • A name change from Blythe Energy Project Phase II to the Sonoran Energy Project. The proposed name change is to reduce potential confusion associated with the number of generating projects in the area using the name “Blythe.”
  • Define a new point of electrical interconnection via a 1,320-foot, 161-kV transmission line to the Western Area Power Administration’s Blythe substation located southeast of the project site via an existing transmission line located in the Southern California Edison (SCE) Buck Boulevard substation.
  • Replace the two Siemens SGT6-5000F combustion turbines with a single, more efficient General Electric (GE) Frame 7HA.02 combustion turbine.
  • Replace the Siemens steam turbine generator (STG) with a more efficient single-shaft GE D652 STG.
  • Increase the size of the auxiliary boiler to support GE’s rapid response fast start capability.
  • Decrease the size of cooling tower from an 11-cell to a 10-cell tower in response to the reduced heat rejection requirements.
  • Decrease the size of the emergency diesel fire pump engine.

“As is demonstrated in the Petition, none of these project modifications will result in an increase in environmental impacts beyond those previously analyzed during the licensing of the Project,” said the cover letter for the petition.

This project has a ten-year history 

In December 2005, the California Energy Commission (CEC) granted a license to Caithness Blythe II LLC to construct and operate the Blythe Energy Project Phase II. As licensed at that point, BEP II was to be a 569-MW, combined-cycle plant consisting of two combustion turbines with fired heat recovery steam generators (HRSGs), a single STG, an 8-cell wet cooling tower, and ancillary equipment. The project site is located in eastern Riverside County, approximately five miles west of Blythe, California.

In October 2009, Caithness Blythe II LLC submitted a Petition to Amend (PTA) that requested project modifications that included:

  • Define a new point of electrical interconnection via a 2,100-foot-long, 500-kV transmission line into the proposed Keim substation.
  • Replace the Siemens Westinghouse V84.3a turbines, which are no longer available, with fast-start Siemens SGT6-5000F turbines.
  • Modify the combustion turbine and steam turbine (ST) enclosure.
  • Incorporate an auxiliary boiler to allow fast start technology.

The commission approved the amendment request in April 2012. In a parallel request, in October 2011, Caithness Blythe II submitted a PTA to extend the BEP II license. The commission approved this amendment request in December 2011, extending the license to Dec. 14, 2016. To date, construction of the project has not commenced.

In May 2014, the current owner of BEP II, AltaGas Sonoran Energy, submitted a Notice of Name Change/Petition to Change Ownership to the commission. The Commission approved the ownership change on June 18, 2014.

Newly designed plant can start faster to support variable renewable energy output

Said the Aug. 7 application about this latest project design change: “The combustion turbine/steam turbine technologies being proposed were unavailable during the licensing of the project. Further, AltaGas Sonoran Energy Inc. acquired the SEP site license in May 2014 and has been working since that time on developing a project that will support the integration of renewables by providing efficient, fast-starting, fast-ramping, lower-minimum-operating-load, highly-efficient combined-cycle gas-fired generation that will utilize dry combustors and water treatment of cooling tower influent and share certain infrastructure with the existing, operational Blythe Energy Project (referred to herein as the existing BEP).”

The Sonoran Energy Project (SEP) will be a natural gas-fired, water-cooled, combined-cycle, 553-MW (net) facility, laid out using one-on-one single shaft arrangement utilizing a GE 7HA.02 gas turbine and a D652 steam turbine. The power block will consist of one natural gas-fired combustion turbine generator (CTG), one supplemental-fired HRSG, one steam turbine, an induced-draft cooling tower, and related ancillary equipment. Other equipment and facilities to be constructed are an auxiliary boiler, water treatment facilities, emergency services, and administration and maintenance buildings.

SEP will share some facilities with the existing BEP, including an existing 16-inch natural gas line located on the south side of the BEP property boundary. The gas line will be extended north to a new SEP conditioning and regulating station.

The interconnection is an approximately 1,320-foot, 161-kV transmission line from SEP to the existing Western Area Power Administration’s Blythe substation. The Blythe substation is located on a separate parcel southeast of the SEP site.

The power blocks will encompass the following principal combined design elements:

  • One GE 7HA.02 CTG with a nominal rating of 333 MW. The CTG will be equipped with an evaporative cooler on the inlet air system and dry low oxides of nitrogen oxide (NOx) combustors.
  • One GE D652 three casing, four bearing single, shaft configuration, double flow, side exhaust condensing steam turbine.
  • One HRSG, which will be horizontal, triple-pressure, and natural circulation. The HRSG has a natural gas-fired duct burner for supplemental firing in the HRSG inlet ductwork and an emission reduction system consisting of a selective catalytic reduction (SCR) unit to control NOx stack emissions, and an oxidation catalyst to control carbon monoxide (CO) emissions in the outlet ductwork.
  • One induced-draft, 10-cell cooling tower to provide cooling to the surface steam condenser and closed cooling water heat exchanger.

The auxiliary steam boiler will provide steam during gas turbine start-up and shutdown to allow startups and shutdowns to be accomplished more quickly. The boiler will provide up to 60,000 pounds per hour of steam to warming the steam turbine, maintaining vacuum on the steam condenser, and heating/reheating condensate.

SEP will be capable of being dispatched throughout the year and will have annual availability of 95%. It will be possible for plant availability to exceed 99% for a given 12-month period. SEP will be operated from the BEP control room. As such, the incremental increase in operational staffing for SEP is expected to be nine employees, including five plant operators, one administrative person, two mechanics, and one plant engineer, in three rotating shifts. The facility will be capable of operating 24 hours per day, 7 days per week.

SEP is expected to operate at full load, although the plant will have the ability to serve both peak and intermediate loads with the added capabilities of rapid startup, low turndown capability (ability to turn down to a low load of 30% of the combustion turbine’s output, depending on ambient conditions), and steep ramp rates (50 MW per minute when operating above minimum gas turbine capacity).

The applicatiion said: “The project configuration will be more efficient than many, if not all of the existing gas-fired steam generation facilities in southern California. SEP will provide much needed flexible operating characteristics for integrating renewable energy into the electrical grid and providing fast response load following service. SEP is expected to have an annual capacity factor of between 35 and 80 percent. The actual capacity factor for SEP in any month or year will depend on weather-related customer demand, load growth, renewable energy supplies, generating unit retirements and replacements, the level of generating unit and transmission outages, and other factors. The exact operational profile of SEP will ultimately depend on electrical grid needs at the time and dispatch decisions made by the offtaker or load serving entity contracted with AltaGas Sonoran Energy Inc. to buy and distribute the power generated and the [California ISO].”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.