Jordan Cove nears air permit for LNG terminal – and 420-MW power plant

The Oregon Department of Environmental Quality is taking comment until April 3 on a draft air quality permit for the Jordan Cove liquefied natural gas (LNG) project, which includes a 420-MW power project.

This proposal is for a new source consisting of a 420-MW power plant, natural gas cleaning systems, four liquefaction trains, liquefied natural gas storage tanks, and LNG ship load out facilities. The Jordan Cove Energy Project is backed by Jordan Cove Energy Project LP.

This LNG export terminal would be located on an approximate 168-acre site located on the bay side of the North Spit of Coos Bay, Oregon between Coos Bay Navigation Channel Miles (CM) 7.0 and 8.0. The project will consist of facilities to receive, liquefy, temporarily store, and send out up to approximately six million metric tons per annum (MMTPA) of LNG. The LNG terminal will be capable of loading LNG ships ranging in capacity from 89,000 cubic meters (m3 ) to 160,000 m3.

Approximately 90 ships per year are anticipated to call on the LNG terminal. The LNG loaded onto the ships will be transferred by cryogenic service piping from two 160,000 m3 (1,006,000 barrels) full-containment LNG storage tanks where it will be stored in a liquefied state until it is pumped out to the LNG vessels. The following liquefaction facilities are proposed for the project:

  • Four liquefaction trains, each with the capacity of 1.5 MMTPA (million tons per year);
  • Two feed gas cleaning and dehydration trains with a combined natural gas throughput of approximately 1 billion SCF/day (Bscf/d);
  • Refrigerant storage and resupply system;
  • Aerial Cooling System (Fin-Fan) to reject heat removed during the LNG liquefaction process; and
  • The South Dunes Power Plant (SDPP), a nominal 420-MW natural gas fired combined-cycle plant that will power the natural gas liquefaction process systems.

The power plant would have six General Electric LM6000 PG Combustion Turbines that will utilize pipeline natural gas, and which will be equipped with natural gas-fired duct burners for supplementary firing and two steam turbine generators. Steam from the steam turbine will be sent to a condenser where it will be cooled to a liquid state and returned to the heat recovery steam generator (HRSG). Supporting ancillary equipment will include two emergency diesel generators (one at the liquefaction site and one at the South Dunes Station) and five emergency diesel fire pumps to provide on-site fire-fighting capability (four at the liquefaction facility and one at the South Dunes Station).  

Potential annual emissions from the combined cycle units assume the equivalent of 8,760 hr/yr of combustion turbine operation and 4,000 hr/yr of duct firing. Potential annual emissions from the emergency diesel generators and fire pumps are based on 200 hours per year of operation. The combustion turbines will use low-NOx combustion systems in combination with selective catalytic reduction (SCR) add-on NOx control systems.

Approval also being sought from state siting council

The website of the Oregon Energy Facility Siting Council indicates that the company’s application for a site certificate is still pending. Said a December 2014 revision of that siting application: “The SDPP will include two blocks of combined-cycle power. Each block will consist of three CTGs of approximately 56 MW each. Each CTG will have an inlet air filter to ensure that combustion air does not contain any contaminants that could cause physical damage to the rotating parts of the CTG. The CTGs will have two shafts containing a low-pressure compressor section, high-pressure compressor section, combustor, high-pressure turbine section, and a lowpressure turbine section. The low-pressure rotor shaft of the CTGs will be connected to a generator to produce electrical power at a 60-cycle alternating current (AC). The compressor sections in the CTGs will compress the inlet air and supply compressed air to the combustion section of the CTGs, where natural gas will be supplied to provide combustion. The exhaust from the combustion section will first go through the high-pressure turbine section, rotating the CTG high-pressure rotor, before expanding through the low-pressure turbine, rotating the CTG low-pressure rotor, which in turn rotates the generator rotor, producing 60-cycle AC electrical power.

“Hot gases exit the CTGs into the HRSGs where the available energy in the exhaust gas is used to produce high-pressure (HP) steam before discharging the exhaust gas through exhaust stacks to the atmosphere. Additional heat input into the HRSGs can be provided by duct burners that would burn natural gas. The additional heat from the duct burners would produce additional steam for the STGs, increasing the plant electrical output above what can be produced using only the steam from CTG exhaust. Steam produced in the HRSGs will be supplied to STGs and the gas conditioning facilities for process steam.

“Natural gas will be provided to the SDPP from two sources: the Pacific Connector Gas Pipeline (approximately 4 percent), and boil-off gas (BOG) and flash gas (approximately 96 percent) from the JCEP LNG Plant. The 36-inch Pacific Connector Gas Pipeline (PCGP) will enter the SDPP site near the southeast corner of the site. Assuming a 420-MW average generating plant, the total natural gas consumption is estimated at 87 million standard cubic feet per day. Natural gas will be available on a continuous basis from both sources.

“The SDPP will supply uninterrupted power to the LNG Plant and may provide power for distribution for public sale. A one-mile, double-circuit, 115-kV transmission line, will connect the switchyard at SDPP to the gas-insulated substation at the JCEP LNG Plant. Most of this line will be located in the JCEP utility corridor. A second 115 kV transmission line, 2,024 feet in length, will connect the switchyard to the relocated Pacific Power substation in the southeast portion of the SDPP site. This single-circuit 115-kV transmission line will be 71 to 91 feet above the bottom of the baseplate. An interconnection through the Pacific Power substation to the local Pacific Power system or to the Bonneville system through Central Lincoln public utility district (PUD) may be provided at a later date for distribution of power for public sale and local grid stabilization. That interconnection is not part of this application.

“The existing on-site substation for Pacific Power will be relocated to an area in the southeast part of the SDPP site. This substation will provide an alternate source for housekeeping power (via a 115-kV overhead single-circuit line) to the SDPP. This 115-kV transmission line will be available for future sale of power to other entities.”

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.