Document ID: EPA-HQ-OW-2008-0667-3629
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2014-08-15T04:00Z

Site Visit Report
                                       
Scattergood Generating Station
12700 Vista Del Mar
Playa Del Rey, CA 90203
August 31, 2009 (revised August 16, 2013)
Background and Objectives
The Environmental Protection Agency (EPA) is in the process of developing 316(b) cooling water intake structure requirements that reflect the best technology available (BTA) for minimizing adverse environmental impact for all existing power plants and manufacturing facilities.  As part of this process, EPA staff is visiting electric generators and manufacturers to better understand the cooling water intake structure (CWIS) technologies in use at facilities, including the site-specific characteristics of each facility and how these affect the selection and performance of CWIS technologies.  EPA is also visiting facilities to better understand cooling water use and specific issues or technologies that can affect 316(b) compliance.  EPA selected Scattergood Generating Station (SGS) for a site visit due to its location on the Pacific Ocean and its use of an offshore intake structure fitted with a velocity cap.
Facility Description
SGS is a natural gas - fired steam electric generating facility located in the Playa del Rey section of the City of Los Angeles and owned and operated by the City of Los Angeles Department of Water and Power (LADWP).  The facility occupies approximately 56 acres of an industrially zoned site opposite Dockweiler State Beach and Santa Monica Bay.  The city's Hyperion Wastewater Treatment Plant lies adjacent to the facility's northern property line, with Grand Avenue bordering to the south (industrial area).  Residential neighborhoods in the City of El Segundo and Los Angeles abut the eastern and northeastern boundaries (see Attachment B).  In addition, SGS is located approximately one mile south of the southern-most runway at Los Angeles Airport.
Elevations at the site vary significantly.  The three generating units are situated at approximately 35 ft above sea level (asl) along the facility's western boundary with Vista del Mar.  Water treatment ponds and tanks, parking areas, and smaller maintenance buildings are also located at this level.  Immediately east of the generating units, the property rises sharply to approximately 100 ft asl, then gradually rises to 155 feet at the eastern property line.  This upper portion is occupied by the switchyard, storage tanks, and two small cooling towers that provide bearing cooling water using potable water.
Wastewater discharges to and water withdrawals from Santa Monica Bay (Pacific Ocean) are covered under NPDES Permit No. CA0000370, which is administered at the state level by a regional water board.  Order No. 00-083, issued by the Los Angeles Regional Water Board, expired on May 10, 2005 but has been administratively continued to the present.  The facility had been previously notified that a reissued permit was delayed pending the outcome of the State Water Board's ongoing once-through cooling policy development.  At the time of EPA's site visit it was unclear when the NPDES permit would be reissued. 
Power generation began in 1958 with the commissioning of Unit 1.  Unit 2 followed in 1959 while Unit 3 was commissioned in 1974.  All units remain available for service.
SGS has a single two to three week outage annually and an eight to ten week outage every few years for major projects.
Electricity Generation and Transmission
SGS currently operates three conventional steam turbine units (Unit 1, Unit 2, and Unit 3) with a combined boilerplate generating capacity of 820 MW (Table 1). Facility representatives noted that the capacity utilization rate (CUR) at SGS has consistently trended downward over recent years as more modern and efficient sources have come online in the region, including an expanded renewable portfolio to meet state greenhouse gas objectives.  However, depending upon federal and state climate legislation, greater dependence on these local plants for base load energy supply and the balancing of new intermittent renewable resources may be necessary if LADWP is required to undertake an early divestiture of its coal resources.
                        Table 1  -  SGS Rated Capacity
Unit
Rated capacity
(MW)
2008 CUR
Unit 1
                                      180
                                      31%
Unit 2
                                      180
                                      15%
Unit 3
                                      460
                                      18%
SGS total
                                      820
                                      20%

Units 1 and 2 are conventional natural gas while Unit 3 is a supercritical natural gas unit.  Energy efficiencies for SGS's three natural-gas fired units are typical for units of this type and age.  Under peak conditions, Units 1 and 2 can operate at approximate efficiencies of 33% (9,500 BTU/kWh) while Unit 3 is slightly more efficient at 37% (9,200 BTU/kWh).
LADWP representatives noted that capacity utilization rates are an inexact metric for determining a particular facility's importance to the overall system.  Although SGS's CUR is relatively low, it occupies a critical position in LADWP's overall generation and transmission plans during peak periods.  The existing transmission system is limited in its ability to move electricity between the northern and southern sections of LADWP's service areas during high demand periods.  The physical location of SGS, along with LADWP's other coastal units, enables LADWP to maintain a proper balance in the system without compromising service.  This is particularly notable since LADWP is its own balancing authority and as mentioned in Section 10 of this report, as a vertically integrated utility responsible for its own generation, transmission, and distribution of electricity, does not rely on the energy market for power purchases to supply its energy needs.  Therefore, the role of its coastal plants, serve a critical function in providing local resource adequacy, reliability, and system stability.
Cooling Water System and Intake Structure
Units 1-3 use ocean water for condenser cooling in a single-pass configuration ("once-through cooling").  SGS operates a single combined intake structure to serve all three units; water is divided after secondary screening to dedicated tunnels to each unit's condenser.  Water is withdrawn from Santa Monica Bay through an intake located approximately 1,600 feet from shoreline, terminating at a depth of approximately 29 feet.  The intake pipe rises 13 feet above the sea floor and is fitted with a circular concrete velocity cap 32 feet in diameter (Figure 1).  There is a 5 foot vertical gap between the top of the intake pipe and the bottom of the velocity cap.  In February 2009, SGS installed vertical exclusion bars spaced 9 inches apart on the velocity cap to reduce entrapment of large organisms (sea lions, sea turtles, etc.).  Facility representatives indicated that the modification has noticeably reduced entrapment between the intake riser and the forebay. 

                                       
Figure 1  -  Offshore Intake and Velocity Cap
The intake structure's onshore portion consists of 8 screen bays arranged in a 60° arc that draw water from a common forebay.  Unit 3 is served by four of the screen bays, with 2 each dedicated to Units 1&2.  Primary screening is achieved with vertical bar racks spaced 5 inches apart (4-5/8 inch opening) to remove large debris.  Secondary screens for smaller debris consist of vertical traveling screens with 3/8-inch by 3/4-inch mesh openings (Figure 2).  Screens are rotated once every 8 hours, at a minimum, and washed with a high pressure spray to remove collected debris, which is deposited in collection baskets for disposal in a landfill.

                                       
Figure 2  -  Onshore Intake Structure
Estimated intake velocities were calculated using the maximum intake flow and total screen area at MLLW: 
         * 1.5 fps at velocity cap opening
         * 6.8 fps in the intake pipe
         * 0.6 fps approach to screens for Units 1&2
         * 0.7 fps approach to screens for Unit 3
Four circulating water pumps, each rated at 39,000 gpm (56 mgd), serve Units 1&2.  Four additional pumps serve Unit 3, with each pump rated at 47,000 gpm (68 mgd).  The SGS design intake flow (DIF) is 344,000 gpm, or 495 mgd, although the peak intake capacity is used infrequently throughout the year.  Data provided by SGS representatives shows the average daily intake flows from 2005 through 2008 (Table 2).
Table 2  -  Average Annual Intake Flows
Year
Average Annual Intake Flow (mgd)
Percentage of DIF
2005
                                      294
                                      59
2006
                                      316
                                      64
2007
                                      271
                                      55
2008
                                      315
                                      64

A direct correlation between flow and generating capacity utilization cannot be easily made since generating CUR do not account for startup/shutdown periods, nor do they account for "hot standby" periods during which units are held in a near-ready state without generating electricity but still require cooling water withdrawals. 
SGS conducts periodic heat treatments (approx. every 8 weeks) to control biofouling (e.g., mussel growth) in the cooling water system.  During heat treatment control gates on the intake and discharge tunnels are closed while a bypass gate is opened allowing all water to recirculate through the system until the temperature has reached 115° F and has circulated for 100 minutes. 
Biofouling is also controlled through periodic chlorine (sodium hypochlorite) injections to the intake flow.  Chlorination for each unit occurs for 40 minutes once for each shift (3 times per day).
Impingement and Entrainment Information
Following the adoption of the Phase II rule, SGS initiated compliance activities by submitting a Proposal for Information Collection (PIC) in October 2005 that outlined plans to conduct a source water characterization study.  Impingement and entrainment technologies would also be evaluated for their potential use at the site.  The PIC identified fine-mesh traveling screens, cylindrical wedgewire screens, operational measures, and restoration as technologies that might offer some benefit to SGS.  These evaluations were not completed, however, due to the suspension of the Phase II rule. 
Facility representatives noted that LADWP evaluated the feasibility of using treated wastewater from the Hyperion facility as a replacement for ocean water at SGS, but concluded this water source was insufficient to meet cooling water needs.  In addition, this alternate water source may be limited in the future because the state is advocating water reclamation, thereby reducing opportunities for reclaimed water from POTWs.  Secondary issues included the elevated wastewater temperature coming from the Hyperion facility an the presence of ammonia which would be detrimental to the copper/nickel alloy condenser tubes.
At the direction of the Regional Water Board, SGS conducted a source water baseline characterization study during 2006 to determine the composition and abundance of all life stages of fish and shellfish that might be influenced by the intake structure.  The study documented entrainable organisms in the vicinity of the intake and near the shoreline, but did not attempt to quantify any entrainment reductions.  SGS collected monthly sampling every six hours in a 24 hour period at from ten source water stations located up and down the coast.  SGS also conducted impingement and entrainment sampling as part of this study.  They collected weekly (four in a 24 hour period) impingement samples at the traveling screens and entrainment samples from a single entrainment station in the immediate proximity of the CWIS (within 50-100 meters).  The study was published in November 2007.
SGS has twice evaluated the effectiveness of the intake structure's velocity cap in reducing impingement.  Following a major storm in 1970 that destroyed the velocity cap, SGS operated for 4 years without the cap.  Comparisons between the protected and unprotected system showed significant impingement reductions with the velocity cap in place. 
More recently, SGS conducted a study over four months during the winter of 2007-08.  During the study period, intake and discharge flows were reversed (i.e., the intake became the discharge and vice versa) such that the new "intake" was unprotected.  Apart from the velocity cap, the principal difference between the intake and discharge is the distance from shore (1,600 vs 1,200 feet).  At this location, however, the sea floor slopes gently away from shoreline and translates to a depth disparity of only a few feet.  Thus, the species composition and abundance are substantially similar at each location.  The study reported impingement reductions of more than 97 percent based on abundance, and 95 percent based on biomass.  A single species, pacific sardines, accounted for over 94% of fish abundance.
Entrainment has not been studied in detail at SGS.  The velocity cap study did not evaluate any potential entrainment reduction that might be achieved by the intake structure's location at a point offshore. 
Cooling Tower Feasibility
Facility representatives noted that the feasibility of cooling towers at the SGS location as been considered at different points, whether as part of a repowering project or to retrofit one or all three of the existing units.  SGS has not conducted a formal cost and engineering feasibility analysis, however. 
A report prepared for the California Ocean Protection Council (OPC) and State Water Board in 2008 identified several obstacles that would influence the feasibility of cooling towers at the SGS location.  Available space at the facility is limited and cooling tower placement would be complicated by the disparity in elevations.  Siting cooling towers to either side of the generating units at the 30 foot elevation would be difficult given the limited space, the presence of other structures (treatment ponds/tank) and potential air circulation interference due to a tower's proximity to the steep slope east and south of the generating units. 
A more likely scenario would place cooling towers on the upper portion of the facility at the 100 foot elevation where the current, but significantly smaller cooling towers for just the bearing cooling water, are located.  Multiple towers could be configured in this area, although the elevation difference between the towers and condensers would require larger capacity circulating water pumps and might require modifications to the condensers to withstand higher pressures.  Towers at this location would present a greater visible impact and might contribute to drift deposition on the adjacent switchyard. 
The potential for a large visible plume would likely require mitigation for at least a portion of the year.  SGS's proximity to the southernmost runway at LAX and to residential neighborhoods in El Segundo would seem to indicate that plume abatement technologies would be required.  Noise abatement measures, such as low-noise fans or fan deck barriers would also be required to comply with local ordinances.  The 2008 OPC study considered these obstacles but was able to configure cooling towers for all three units on the upper portion with plume and noise abatement technologies included.  The initial capital cost for these towers was estimated at $160.4 million, excluding long-term costs such as operation and maintenance and energy penalty costs.
During the site visit, facility representatives cited many of the same obstacles as potential reasons why cooling towers were infeasible at the site.  Space limitations and conflicts with local ordinances were the primary reasons why SGS does not consider cooling towers a practical alternative.  Representatives noted that likely local opposition to cooling towers is not reflected in local building and noise ordinances and would be a major concern.  Other concerns that were not reflected in the OPC study were: (1) while the report suggests relocation of critical, integral site equipment (e.g. ammonia storage tanks for NOx compliance, or the switch yard) their costs and the associated outage time (e.g. replacement power costs) were not captured; (2) OPC concluded relocation of the switch yard was feasible, but is considered infeasible by LADWP for all sites evaluated; (3) the suggested siting location for the cooling towers was characterized as sufficiently large (with equipment relocations), however, it resulted in a less than desirable configuration (roughly perpendicular to prevailing winds); and (4) the study assumes that the new towers could replace the need for the existing cooling towers for cooling the bearing (which would be required to be demolished to make room), but recognized that it was unknown whether the use of salt water for these systems could be tolerated.  Most significantly, however, representatives noted that retrofitting the existing once-through cooling systems with cooling towers made little economic sense given the age and capacity utilization of each unit.  In addition, because SGS is a municipal utility, retrofit funds would require a rate increase and bond issuance that would have to be approved by the Los Angeles City Council.  See Section 10.0.
Debris Handling
Debris is not a significant issue at SGS due to the intake's deep offshore location.  Any debris captured on the bar racks or traveling screens is disposed of in a landfill. 
Repowering/Future Uses
LADWP is considering the possibility of repowering Units 1 and 2 or Unit 3 by 2015.  The state's final once-through cooling policy will likely influence the options selected for any repower project.
Cooling Ponds
SGS does not use cooling ponds for condenser cooling.
Ownership
LADWP is the largest municipally owned utility in the country with a service population of approximately 4 million people.  LADWP maintains a total generating capacity of approximately 7,200 MW from diverse portfolio of fossil, hydroelectric, renewable, and nuclear units.  SGS is one of three LADWP-owned facilities on the California coast that continues to use once-through cooling (together with the Harbor and Haynes Generating Stations). 
As a vertically integrated utility, LADWP owns and operates the generating, transmission and distribution systems that provide electricity to a dedicated customer base.  This transmission system is not limited to the City of Los Angeles, but extends into Nevada, Utah, and Arizona.  The system is used to import power to all locations (LADWP owned and power exchanges with other utilities).  This differs from many investor owned utilities, such as Pacific Gas & Electric or Southern California Edison, which must rely on the open market to procure a significant portion of their electricity needs. 
LADWP must obtain approval from the Los Angeles City Council to implement any electricity rate increases.  LADWP is in the process of developing a new IRP and is currently soliciting input from the public on this new guidance document.  This new 2010 IRP will help set the course that LADWP will take in determining the best path to take for repowering the existing OTC facilities. 
316(a)
Thermal discharges to surface waters are governed by the state's Thermal Plan (1972), which creates separate requirements for new and existing thermal discharges to ocean waters.  As an existing thermal discharger, SGS is subject to the Thermal Plan's narrative requirement that any thermal discharge must ensure protection of identified beneficial uses.  This requirement is incorporated into the existing permit as a temperature limitation of no more than 100° F during normal operation and 135° F during heat treatments.  The facility does not have a 316(a) variance for thermal discharges and has complied with the existing limitation during its most recent permit cycle. 
Ash Handling
SGS does not generate any ash.
Air Emissions Controls
Each unit at SGS employs selective catalytic reduction to minimize NOx emissions.
Additional Information
Facility representatives noted that an ongoing legal battle over the availability of emission credits within the South Coast Air Quality Management District have raised the possibility that no new projects would be able to obtain the necessary air permits.  This would include facilities retrofitted with wet cooling towers. 
SGS's current NPDES permit, adopted in 2000, does not contain any numeric or narrative limitations regarding impingement or entrainment due to cooling water withdrawals.  The permit carries over findings from previous permits that essentially concluded the SGS cooling water system represented the "best technology available" for compliance with 316(b).  Although these determinations were made prior to the adoption of the state policy on once-through cooling, future studies will determine whether this statement is still accurate or whether other technologies are available that would represent "best technology available" with costs that can be borne by industry.  SGS is required to conduct semi-annual impingement monitoring coinciding with scheduled heat treatments. 
In addition to once-through cooling water, SGS discharges a small volume of wastewater from several low volume waste streams.  These low volume wastes consist of cooling tower blowdown, boiler blowdown, floor drains, and settling basin discharges, and are commingled with once-through cooling water prior to discharge through the main outfall.  All wastewater is discharged to Santa Monica Bay through a submerged conduit terminating at a point 1,200 from shore.
Metal cleaning wastes (chemical and non-chemical) are typically captured in portable Baker tanks and treated offsite. 
SGS must comply with both water quality-based and technology-based effluent limitations for its wastewater discharge to Santa Monica Bay.  In 1988, the State Water Board granted a variance to the total residual chlorine water quality standard for biofouling control in the cooling system.  EPA granted a similar variance for the total residual chlorine effluent limitation applicable to steam electric facilities.  It is not clear if these variances will be revisited in any future permit reissuance.

Attachments

Attachment A		List of Attendees
Attachment B		Aerial Photos
Attachment C		Facility Flows
Attachment D		Alden Report for Phase II Compliance (December 2003)
Attachment E		Addendum to Alden Report for Phase II Compliance (May 2007)
Attachment F	Impingement Mortality and Entrainment Study (November 2007)
Attachment G	Impingement Mortality and Entrainment Study Appendices (November 2007)
Attachment H	Revisions Requested by LADWP

Attachment A--List of Attendees

Paul Shriner, EPA
Jan Matuszko, EPA
John Kemmerer, EPA Region IX
Tim Havey, Tetra Tech
Kelly Meadows, Tetra Tech
Michael Hanson, LADWP
Hamid Nejad, LADWP
Peter Rudd, LADWP
Kim Burmahln, LADWP
Susan Damron, LADWP
Dipak Patel, LADWP
Dawson Dong, LADWP
Ian Guthrie, LADWP
Katherine Rubin, LADWP

See also Attachment A (DCN 10-6545A accompanying this document) for the sign-in sheet.

Attachment B -- Aerial Photos
See also DCN 10-6545B accompanying this document.

                                       
                                       

                           Aerial View Looking West

                                       
                           Ground View Looking North
                                       

                         Aerial View Looking Northeast

Attachment C--Facility Flows

Please see DCN 10-6545C accompanying this document.

Attachment D--Alden Report for Phase II Compliance (December 2003)

Please see DCN 10-6545D accompanying this document.

Attachment E--Addendum to Alden Report for Phase II Compliance (May 2007)

Please see DCN 10-6545E accompanying this document.

Attachment F--Impingement Mortality and Entrainment Study (November 2007, Revised)

Please see DCN 10-6545F accompanying this document.

Attachment G--Impingement Mortality and Entrainment Study Appendices (November 2007, Revised)

Please see DCN 10-6545G accompanying this document.

Attachment H -- Revisions Requested by LADWP

In their comment letter on the proposed rule, LADWP requested that EPA make certain revisions to the Scattergood site visit report in addition to their previous comments. These revisions are below.

1) Replacement for the first paragraph of section 14.0 (Additional Information).

Instead of 
"Facility representatives noted that an ongoing legal battle over the availability of emission credits within the South Coast Air Quality Management District have raised the possibility that no new projects would be able to obtain the necessary air permits.  This would include facilities retrofitted with wet cooling towers."
the text should read

      "Permits from the AQMD for repowers of the existing units are viable since emission offsets are available on a megawatt for megawatt replacement of existing boilers with new, advanced gas turbine units."

2) Edits to the last paragraph of section 2.0 (Facility Description)

Instead of

"SGS has a single two to three week outage annually and an eight to ten week outage every few years for major projects."

the text should read

"SGS has a single two to three week outage for each unit annually and an eight to ten week outage for each unit every five to seven years for major projects."

3) Edits to the first sentence of section 3.0 (Electricity Generation and Transmission)

Instead of

      "SGS currently operates three conventional steam turbine units (Unit 1, Unit 2, and Unit 3) with a combined boilerplate generating capacity of 820 MW (Table 1)."

The text should read

      "SGS currently operates three conventional steam turbine units (Unit 1, Unit 2, and Unit 3) with a combined generating capacity of 820 MW (Table 1)."
      

4) Revisions to the first sentence of second paragraph of section 3.0 (Electricity Generation and Transmission)

Instead of

      "Units 1 and 2 are conventional natural gas while Unit 3 is a supercritical natural gas unit."

The text should read

      "Units 1 and 2 use a conventional natural gas-fired boiler while Unit 3 uses a supercritical natural gas-fired boiler."