OREGON DEPARTMENT OF ENVIRONMENTAL QUALITY

OREGON TITLE V OPERATING PERMIT

REVIEW REPORT

Western Region

750 Front Street, #120

Salem, OR 97301-1039

TABLE OF CONTENTS

INTRODUCTION  3

PERMITTEE IDENTIFICATION  8

FACILITY DESCRIPTION  9

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING  36

PLANT SITE EMISSION LIMITS  44

HAZARDOUS AIR POLLUTANTS  46

OTHER PERMITS  47

COMPLIANCE HISTORY  47

SOURCE TEST RESULTS  47

PUBLIC NOTICE  47

EMISSIONS DETAIL SHEETS  51

LIST OF ABBREVIATIONS THAT MAY BE USED IN THIS REVIEW REPORT

INTRODUCTION

1.  The proposed permit is a renewal of an existing Oregon Title V Operating Permit (No. 36-6142), which was issued January 1, 2003, and was originally scheduled to expire on December 1, 2007. However, because a timely permit renewal application was submitted by SP Newsprint, the current permit will remain in effect until such time as the renewed permit is issued.

2.  In accordance with OAR 340-218-0120(1)(f), this review report is intended to provide the legal and factual basis for the draft permit conditions. In most cases, the legal basis for a permit condition is included in the permit by citing the applicable regulation. In addition, the factual basis for the requirement may be the same as the legal basis. However, when the regulation is not specific and only provides general requirements, this review report is used to provide a more thorough explanation of the factual basis for the draft permit conditions.

3.  During the prior permit period the following modifications were made to the permit.

4.  The following is a list of condition-by-condition changes between the previous permit and the proposed permit.

PERMITTEE IDENTIFICATION

5.  SP Newsprint Co. operates a newsprint paper mill in Newberg, Oregon. The source uses thermomechanical pulping processes and a recycled paper process (Deinking Plant) to supply the pulp that is processed into newsprint quality paper. These processes do not have the characteristic odorous emissions of kraft or sulfite pulping mills. The sulfite pulping process at this facility was discontinued in 1984.

FACILITY DESCRIPTION

6.  Basic Paper Making – Currently wood chips, old newsprint (ONP) and other recycled paper are the main raw materials used to manufacture newsprint at this facility. Water, heat, chemicals, and mechanical energy are used to swell and separate the fibers in the wood chips to create a pulp. The pulp is screened and cleaned to create a more uniform pulp. The recycled paper is conveyed to a continuous pulper that uses recycled water from the paper machines to make a pulp slurry. Ink is removed from the resulting pulp in a proprietary process. The de-inked pulp is screened, filtered, and brightened with non-chlorinated agents. The final product is concentrated and stored in a high-density storage chest for later use in papermaking. Two paper machines (Paper Machines #5 and #6) take the pulp and form a continuous sheet and then extract and evaporate the water. The solid sheet is then wound onto a large reel which is rewound into smaller rolls for use in newspaper pressrooms. A major upgrade to the Deink Plant was completed in 2001 that facilitated the pulping and deinking of old magazines and residential mixed pack paper. In addition, a new ink removing process was installed that produces a brighter pulp using a reduced amount of chemicals.

Power Plant – The power plant is the source for all of the mill’s steam needs and most of its electrical power needs. Two main boilers (Boilers #9 and #10) are used to generate high pressure steam which is used to make electricity by processing the steam through turbine generators. The #2 Turbine Generator (#2 T.G.) is a full condensing turbine generator that utilizes the 900 PSI steam from the #10 Boiler. The #1 T.G. is an extraction unit turbine generator that utilizes 600 PSI steam from the #9 Boiler, and steam from the #10 Boiler which has been reduced to 600 PSI. Once the steam has passed through the turbine generators, the lower pressure steam is then used in other processes throughout the plant. The steam plant can produce all of the mill’s energy requirements. In addition to the two large boilers, the facility has two small boilers (#6 and #7) which are used for backup steam, in the event that either of the two large boilers are not operating. The two, small, natural gas fired boilers are designed to only produce steam for the plant’s production needs and are vented to a common stack.

In 2003, two cogeneration combustion turbines with auxiliary duct burners were installed to produce electricity and steam. In 2007 one of the combustion turbines (CTG #2) was removed from the mill site.

The turbine is capable of producing approximately 46 megawatts of electricity and 87,000 pounds of steam per hour from the heat recovery system. With the supplemental duct burner the system is capable of producing a total of 275,000 pounds of steam per hour.

Wastewater Treatment System – The paper making process requires large quantities of water. The paper mill draws water from the Willamette River and purifies it through a series of settling ponds and sand filters prior to use. After the purified water is used in the boilers and the paper making process, it is piped to a primary clarifier to remove a large portion of the solids. Effluent from the primary clarifier is sent to the secondary treatment system that contains microorganisms which “eat’ organic compounds and reduce the biological oxygen demand (BOD). The effluent is treated in the north lagoon and the activated sludge plant. It then processed through a secondary clarifier to remove more solids and to recycle the microorganisms from the activated sludge plant. Effluent is then sent to a second lagoon to provide addition aeration and polishing prior to returning the water to the river in accordance with the facility’s DEQ waste water discharge permit.

The solids that are removed from the paper mill effluent are sent to sludge presses where most of the water is removed from the sludge. The sludge is approximately 3% solids content prior to being pressed. The pressed sludge is approximately 40% solids content. The sludge may be processed in the Hog Fuel Dryer to further remove moisture prior to being burned in the hog fuel boilers.

Deink Plant – The deink plant has the capacity to supply more than half of the paper mill’s pulp needs. Recycled paper is processed in a pulper that uses mechanical energy to blend the recycled papers with chemicals and water. The resulting pulp is cleaned and screened to remove inks and dirt and then concentrated and stored until used. The deinked pulp is mixed with non-chlorine brightening chemicals and pumped to additional storage tanks. From the storage tanks the deinked pulp is sent to the #5 Blending Chest or the #6 Blending Chest to be mixed with the TMP/RMP pulp.

Thermal Mechanical Pulp (TMP) & Refiner Mechanical Pulp (RMP) – In the TMP process wood chips are cleaned and steamed prior to being ground (refined). Refiners, driven by large motors, provide the mechanical energy to convert the wood chips to pulp that is screened and cleaned to remove contaminants. The pulp is mixed with non-chlorine brightening chemical (Sodium Hydrosulfite) in the refiners and in the line going to the TMP/RMP storage tanks. From the storage tanks the pulp is sent to the #5 Blending Chest or the #6 Blending Chest. Refiner mechanical pulp is produced without using high temperatures and steam; otherwise the process is the same.

Heat from the #1, 5 & 6 refiner lines is collected and then processed through a heat recovery unit that warms the refiner mill white water.

Paper Machines – The paper making process can be broken down into six steps:

a.  Pulp System

b.  Forming Section

c.  Wet Press Section

d.  Drying Section

e.  Calender and Reel

f.  Winding

Pulp System: Pulp from the Deink and TMP/RMP mills are blended and processed through a multi-stage screening and cleaning system. A deculator (vacuum) is used to remove entrained air from the pulp.

Forming Section: Blended pulp is sent to the headbox where, under pressure, the pulp is evenly distributed onto the forming section of the paper machine. At this point the pulp consists of roughly 99% water and 1% pulp.

Wet Press Section: The paper machines uses woven fabrics with vacuum to form a sheet of paper (approximately 14% solids). The paper then enters the press section where felts, vacuum and rolls are used to squeeze out more water. The fibers now begin to bond and form a smooth surface. The sheet at this time contains approximately 45% solids.

Drying Section: The sheet enters the dryer section where steam is injected into dryer cans to heat the sheet to approximately 180°F. Water in the sheet evaporates and is exhausted by dryer hood fans. The sheet is now approximately 92% solids.

Calender and Reel: Once the sheet has left the dryer section it is calendered, using steel rolls to increase smoothness and to even out the caliper. The sheet is then wound onto reels and transported to the winder.

Winding: The winder is used to create a roll of paper based on the customer requirements for width and diameter. Finished rolls are then wrapped and shipped by truck or rail car to the customer.

Raw Materials – Raw materials used at this facility include recycled paper, wood chips, bulk chemicals, and solid fuels.

Recycled paper is received at the facility by truck and rail car. It is stored in an on site warehouse until it is processed by the Deink plant (DI-EU).

Wood chips used to make virgin pulp are delivered to the mill by truck and are temporarily stored in chip piles (CSP) until used. The chips are pneumatically transferred from the piles to the TMP/RMP process (TMP-EU) via cyclones (CHS-EU).

Bulk chemicals used in the paper making process generally consist of water treatment chemicals, non-chlorine pulp brightening agents, recycled paper emulsifying agents, and paper making additives.

Solid fuels used by one or both of the hog fuel boilers include the following:

▪  Hog fuel (HF) is delivered to the mill by truck and is stored in a pile until fed to the boilers. Part of the HF comes to the facility in a form that is ready to be fed to the boilers. However, the facility has the capability of receiving waste wood and then running it through a hog. Hog Fuel is a mixture of woody materials, which includes shredded waste wood residuals from logging and wood milling operations (approximately 60-80% by weight; primarily tree bark, wood chips, wood shavings and sawdust), waste wood (approximately 20-40% by weight; primarily used pallets, construction debris, demolition debris, and landscaping debris), and processed cellulose (approximately 1-5% by weight; primarily paper, cardboard, and cardboard rejects). In addition, hog fuel typically contains a small amount of plastic from construction and demolition debris.

▪  Fiber based fuel (FBF) is also called Mixed Waste Paper, MWP, or Mixed Scrap Paper, MSP. Fiber Based Fuel is usually sorted cellulose products from collected waste. FBF consists of 95% waste paper and cardboard products, and small amounts of plastic and other materials. FBF can be either cubed or shredded. FBF is stored in a separate building to keep it separate from other HF sources and fed to #10 boiler. The emissions of particulate matter from the receiving, storage, and distribution of FBF have been determined to be insignificant and are included in the AI emissions unit.

▪  Tire derived fuel (TDF) includes shredded tires delivered in 1-inch by 2-inch strips and is stored in a separate pile until it is used. The emissions of particulate matter from the receiving, storage, and distribution of TDF have been determined to be insignificant and are included in the AI emissions unit.

▪  Creosote treated wood fuel (CTWF) will be used as fuel in Boiler #10 only. CTWF includes chipped, shredded, or hogged railroad ties and telephone poles. The source has demonstrated that hogged, creosote treated wood is not a hazardous waste. The following tests were performed on the fuel: TCLP Extraction (SW-846 1311), TCLP Volatile Organic Analysis (SW-846 8240), TCLP Semivolatile Organic Compounds (SW-846 8270), RCRA Metals Analysis (SW-846 6010) for lead only, Pesticide Analysis (SW- 846 8080), and Herbicide Analysis (SW-846 8150). The emissions of particulate matter from the receiving, storage, and distribution of TDF has been determined to be insignificant and is included in the AI emissions unit.

▪  Sludge is mostly rejected cellulose fibers from the mill’s pulp and paper manufacturing processes which is collected from the mill’s wastewater treatment system. The sludge is pressed and may be dried to remove moisture to enable it to be burned. The emissions of particulate matter from the storage and handling of sludge has been determined to be insignificant and is included in the AI emissions unit.

▪  Dried Biosolids Fuel is sludge from municipal wastewater treatment facilities that has been dried to moisture content of about 8%. The dried biosolids will be conveyed to the solid fuel storage area from the co-located biosolids dryer that is owned and operated by another company. Particulate matter emissions from the storage and handling of this fuel have been determined to be insignificant and are included in the AI emissions unit.

▪  Miscellaneous Fuels that are not defined or listed above can be used in the hog fuel boilers provided they are not a hazardous waste and the total amount combusted does not exceed 30% of the total fuel heating value on an annual basis. All ODEQ normal regulations apply to this fuel classification.

FACILITY HISTORY

7.  A summary of the facilities ownership and major changes in operations are listed below.

1892  Sawmill installed at this site by Charles Spaulding.

1927  Spaulding Pulp & Paper added a calcium based acid sulfite pulp mill. Plant produces unbleached pulp for market.

Pre-1943  Boiler #1 installed producing 40,000 pounds steam/hour. Fired on hog fuel, bunker C oil, and natural gas. This boiler was removed in about 1969.

Pre-1943  Boiler #2 installed producing 20,000 pounds steam/hour. Fired on hog fuel, natural gas, and bunker C oil. This boiler was removed in about 1969.

Pre-1943  Boiler #3 installed producing 20,000 pounds steam/hour. Fired on hog fuel, natural gas, and bunker C oil. This boiler was removed in about 1969.

Pre-1943  Boiler #4 installed producing 20,000 pounds steam/hour. Fired on hog fuel, natural gas, and bunker C oil. This boiler was removed in about 1969.

Pre-1955  Boiler #5 installed. 25,000 pounds steam/hour, natural gas/Bunker C oil fired. This boiler was removed in about 1978.

1965  Facility purchased by Publishers Paper Co.

1967  Boilers #6 and #7 installed. Vented to a common stack. Natural gas/Bunker C oil fired. 125,000 pounds steam/hour each.

1968  Refiner mechanical pulp line installed with a 348 air dried ton per day capacity.

Paper Machine No. 5 (note: No. 1 through No. 4 Paper Machines installed at the Oregon City Mill site) installed to produce newsprint. The paper machine is a single wire model with a newsprint paper production capacity of 160,000 tons per year.

Sulfite pulping mill changed to a magnesium oxide base. Pulping capacity was about 200 tons per day.

Boiler #8 (magnesium oxide recovery boiler) installed. Burns sulfite liquor @ 58% solids with natural gas back up fuel. [note: non reducing atmosphere, thus no TRS emissions] 115,000 pounds steam/hour.

1974  #4 thermo mechanical refiner line installed. 35 tons/day pulping capacity. Removed about 1980.

1975  Hog fuel fired Boiler No. 9 installed. 160,000 pounds steam/hour.

1977  #1 Electrical Generating Turbine (No. 1 TG) installed; about 12 megawatts electrical generation capacity. Excess heat from Boiler No. 9 is used to drive the turbine.

1979  Deinking Plant installed. The plant recycles old newspapers into pulp. Original pulping capacity was 125 tons/day.

1980  Paper Machine No. 6 installed with 210,000 tons/year paper production capacity. Total plant production capacity now 370,000 tons/year of newsprint paper.

Two thermo mechanical pulping lines installed. Production capacities of 210 ADT/day each.

Boiler No.10 installed by Publishers Paper Co. Fuels fired in the boiler include hog fuel, sludge, natural gas, and oil. Particulate matter is controlled by a wet scrubber. Steam production capacity is 300,000 pounds/day.

A 36 megawatt electrical generating turbine (No.2.TG) was installed. Excess heat from Boiler No. 10 is used to drive the turbine.

The capacity of the Deinking Plant was increased but unable to determine the amount from available records.

1984  The sulfite pulping mill was permanently shut down, including Boiler #8.

The last part of the Sawmill to be permanently shut down was the chipper.

1986  Facility purchased by Smurfit Newsprint Corporation.

1990  Deinking Plant was upgraded to 625 tons/day pulping capacity.

1991  Boiler No. 10 wet scrubber replaced with an electrostatic precipitator. PM emissions decrease, but SO₂ emissions increase. However, SO₂ emission credits from the shut down of the sulfite mill offset increases. An ambient air quality impact study was conducted and Boilers No. 6, 7, 9, and 10 were modeled. Modeling results show emission impacts from Boiler No. 10 as acceptable but not the impacts from Boilers No. 6 and No.7 when they burn Bunker C oil. The source has agreed to not burn oil in Boilers No. 6 and No. 7.

1999  Facility purchased by Southeast Paper Company and is now operating under the name SP Newsprint Co.

2001  Deinking Plant upgraded to handle magazines and residential mixed pack paper. Average pulping is capacity 660 tons/day with an estimated maximum pulping capacity of 848 tons/day or about 315,000 tons/year. {848 tons x 371 days} [Note: 371 days is the maximum SP Newsprint accounting year]

Paper Machine No. 5 upgraded from 550 to 575 tons/day of newsprint paper.

Paper Machine No. 6 upgraded from 800 to 850 tons/day of newsprint paper.

Estimated maximum RMP pulping capacity = 69,000 tons/year.

Estimated maximum TMP pulping capacity = 230,000 tons/year.

Plant pulping capacity = Deinking + RMP + TMP =614,000 tons/year.
Note: One ton of pulp produces approximately 0.95 tons of newsprint paper.

Plant newsprint paper making capacity = (575 + 850) x 371 days = 528,675 tons/day.

2003 – The Hog Fuel Screening System (HFSS) that was installed in 2001 was removed from service in about 2003.

May 2003 -- Two Cogeneration Turbines with heat recovery steam generating units installed. Each system is capable of generating 46 megawatts of electricity and 275,000pounds steam per hour.

2004 – The Komline Coil Filter in the wastewater treatment system was removed.

May 2007 -- The #2 Cogeneration Turbine was removed from service. The #2 Heat Recovery Steam Generator remains in service.

FACILITY CHANGES

8.  The following changes were made to this facility during the prior permit period or are proposed for inclusion in the proposed permitting period. The proposed modifications have been reviewed and approved by the Department.

8.a.  NC# 20744 (8/27/03): Boiler #10 – Perform major maintenance on the boiler and replace the ID fan with one with a smaller capacity to reduce power consumption. Project completed on October 11, 2003.

8.b.  NC# 21787 (4/09/06): Deink Plant – Increase the production capacity of the plant to 1000 tons of pulp by eliminating process bottlenecks. Also, install a drum pulper vent to control moisture in the deink plant warehouse. This project had not been completed as of the date of this report.

8.c.  NC# 21792 (4/12/06): Boiler #10 – Modify the inlet duct to the distribution air fan to control the operating temperature. Replace the fan outlet duct. Replace corroded areas of the ESP and stack with stainless steel. Install rotary feeder valves in the ash pipes to prevent the flue gas from by-passing the economizer. Replace 1/3 of the tubes in the 3^rd stage air economizer to repair leaks. Replace the outdated distributed control system (DCS) with a new system. Project completed on September 20, 2006.

8.d.  NC# 22025 (11/30/06): #5 Paper Machine – Increase production capacity throughput from 575 to 590 MDT/day by optimizing process parameters. This project had not been completed as of the date of this report.

8.e.  NC# 22027 (11/30/06): #6 Paper Machine – Increase production capacity throughput from 850 to 875 MDT/day by replacing the drive gear box. This project had not been completed as of the date of this report.

8.f.  NC# 22050 (1/04/07): #1 Cogeneration Turbine – Rebuild the turbine. Project completed on February 17, 2007.

8.g.  NC#22070 (1/22/07): #2 Cogeneration Turbine – Rebuild the turbine. Project completed on February 8, 2007.

8.h.  May 14, 2007: The #2 Cogeneration Turbine/Electrical Generator was removed. The #2 HRSG system for producing steam still remains.

8.i.  NC# 22377 (9/12/07): Deink Plant – A dust control system will be installed in the deink plant warehouse to control interior paper dust with one or more stacks venting to the atmosphere. This project had not been completed as of the date of this report.

EMISSIONS UNIT AND POLLUTION CONTROL DEVICE IDENTIFICATION

Emissions Units

9.  The emissions units at this facility are as follows:

9.a.  Emissions unit Aggregate Insignificant (AI) consists of the following:

(See Appendix B, Page 1 for emission estimates)

9.b.  Emissions unit Boilers #6 and 7 (B67-EU) emitting PM, PM₁₀, CO, SO₂/H₂SO₄, NO_x, and VOC and consisting of the emissions devices Boiler #6 and Boiler #7. These boilers are natural gas fired package boilers that are used to provide steam for the paper manufacturing processes in a backup capacity. Both units are vented to a common stack (85-foot height, 8.0-foot diameter, 721.8 ACFS gas flow rate, 14.4 feet/second exit velocity, and 300ºF gas temperature) that exhausts directly to the atmosphere. Additional information and specifications are provided below.

9.c.  Emissions unit Boiler #9 (B9-EU) emitting PM, PM₁₀, CO, SO₂/H₂SO₄, NO_x, VOC, and Pb and consisting of the following emissions devices: Boiler #9 and Hog Fuel Dryer.

Boiler #9 is designed to generate process steam for the Paper Mill, Refiner Mill, and Deink Plant. The steam passes through an electric turbine (TG-1) which generates electricity (rated at 12 MW) prior to being used in the paper manufacturing processes. Boiler #9 is allowed to combust natural gas, hog fuel, wastewater treatment sludge, tire derived fuel (<1% of total solid fuel combusted) and miscellaneous fuels (< 30% of the total heat input). Particulate matter emissions are controlled by a multiclone and wet scrubber in series.

The Hog Fuel Dryer utilizes the Boiler #9 flue gases to dry a mixture of solid fuels, mostly hog fuel and sludge. The gases exiting the dryer are processed through two high efficiency cyclones to recover the dried fuel. The cyclones are vented to the wet scrubber.

Additional information and specifications for this emissions unit are provided below.

9.d.  Emissions unit Boiler #10 (B10-EU) emitting PM, PM₁₀, CO, SO₂/H₂SO₄, NO_x, VOC, and Pb.

Boiler #10 is designed to generate process steam for electrical generation (TG-2, 36MW) and the paper manufacturing processes. It is a field erected boiler that is equipped with fixed grates, an air spreader stoker solid fuel feeding system, and combination natural gas and oil burners. The boiler is allowed to combust the following: hog fuel, tire derived fuel, fiber based fuel, natural gas, oil, onsite used oil, wastewater treatment sludge, creosoted treated wood fuel, biosolids fuel, and miscellaneous fuels. The boiler exhaust is vented to a multiclone and an electrostatic precipitator in series to control particulate matter emissions.

The two natural gas fired burners located in the firebox are used on startup to warm the boiler up, during grate raking periods to maintain heat, and for supplemental heat.

Ash generated by B9 and B10 and associated control equipment is currently being used by the Riverbend Land Fill as daily cover and it consists of:
(1) About 75% fly ash captured by the multiclones;

(2) About 15% boiler bottom ash;

(3) About 5% Boiler No. 9 scrubber ash; and
(4) About 5% Boiler No. 10 ESP ash.

Additional information and specifications are provided below.

9.e.  Emissions unit Co-generation System No. 1 (CG1-EU) emitting PM, PM₁₀, SO₂/H₂SO₄, NO_x, and VOC and consisting of the following emissions devices: Combustion Turbine Generator #1 and Heat Recovery Steam Generator Unit #1.

The turbine generator is fired on natural gas fuel with water injection to control NO_x emissions and is used to produce electricity. The Heat Recovery Steam Generator uses natural gas fuel and is equipped with a low NO_x burner that is used to produce steam that is used in the paper manufacturing processes. The steam generator unit can use the exhaust from the generator turbine to supplement heat input energy requirements.

Additional information and specifications for the devices in this emissions unit are provided below.

9.f.  Emissions unit Pneumatic Chip Handling System (CHS-EU) emitting PM, PM₁₀, and VOC and consisting of the following emissions devices: #1 Cyclone, #2 Cyclone, #3 Cyclone, #4 Cyclone, #5 & 6 Primary Bin Cyclone, East and West Chip Washer Cyclone, #1 Line Primary Bin Cyclone, #2 Line Primary Bin Cyclone, Chip Screening Cyclone, and Fines Loading Cyclone.

The cyclones are used to pneumatically convey wood chips from the chip pile to the chip screens, from the screens to the storage silos, from the silos to the chip washers, and from the washers to the refiner process.

Additional information and specifications for the devices in this emissions unit are provided below.

9.g.  Emissions unit Chip Storage Pile (CSP) emitting PM, PM₁₀, and VOC.

Wood chips that are to be used for making virgin pulp are stored in an outdoor pile.

Additional information and specifications for this emissions unit are provided below.

9.h.  Emissions unit Deinking and Pulping of Recycled Paper (DI-EU) emitting PM, PM₁₀, and VOC.

Recycled paper (newsprint, magazines, and residential mixed paper) is unbundled and conveyed to a continuous drum pulper that utilizes recycled “white water” from the paper machines. Ink is removed from the resulting pulp in a flotation process. The deinked pulp is screened and then brightened with non-chlorinated bleaching agents. The pulp is then concentrated and stored in a high density storage chest until needed in the paper making process. The deinked pulp is blended with the virgin pulp to produce the final product.

Originally the deinking facility was only able to process old newspapers. A major upgrade of the system was undertaken during 2001 and 2002 that allowed the company to process magazines and non-corrugated waste paper. In addition, a new ink-removing process was installed. The new deinking process produces a brighter pulp using reduced amounts of brightening chemicals. This upgrade did not result in an increase in the facilities pulping capacity.

Additional information and specifications for this emissions unit are provided below.

9.i.  Emissions unit Hogged Fuel Storage Pile (HFSP) emitting fugitive PM, PM₁₀, and VOC and consisting of the Hogged Fuel Storage Pile and the Creosote Treated Storage Pile. Hogged material that is to be burned as fuel in the hog fuel boilers is stored in outdoor piles.

Additional information and specifications for this emissions unit are provided below.

9.j.  Emissions unit Kerosene Cleaning (KU-EU) emitting fugitive VOC and is defined for the purpose of PSEL calculations only.

This purpose of this emissions unit is for calculating VOC emissions that occur during the cleaning of the paper machines with kerosene, diesel #1, heating oil #1, or similar cleaning fluids.

9.k.  Emission unit Manufacturing Aids (MA-EU) emitting fugitive VOC and is defined for the purpose of PSEL calculations only. This is a new emissions unit that was not present during the baseline period.

The purpose of this emissions unit is to track VOC emission changes from a baseline (2005) VOC emission rate of 220,600 pounds/year from chemical usages. These chemicals are used in the various pulp and paper manufacturing processes and the resulting VOC emission releases are accounted for within the affected emissions units. In 2005 the mill decided to switch suppliers for most of the manufacturing aids creating the need for a VOC accounting method to account for these changes. The VOC contained in these products may be emitted, be incorporated or consumed in the mill, or be biodegraded in the waste water treatment system. Prior to the change, 220,600 pounds per year of VOC was contained in the manufacturing aids used to produce 487,000 MDT of paper. The new supplier’s products contain different concentrations of VOC and are applied at different rates. The Manufacturing Aids emission unit is used to account for chemical product changes in the VOC plant site emission inventory.

9.l.  Emissions unit Raw Material and Fuel Receiving and Distribution (MH-EU) emitting PM, PM₁₀, and VOC and consisting of the following emission devices: Chip Truck Dump #1, Chip Truck Dump #2, Chip Scalping Screen, Chip Rotary Screen, Hog Fuel Truck Dump #1, Hog Fuel Truck Dump #2, Hog Fuel Grinder, Creosote Treated Wood Fuel, East Chip Washer, and West Chip Washer

This emissions unit includes the activities associated with the receiving and distribution to storage of pulp chips and the receiving and distribution to storage of solid fuels used in the boilers.

Additional information and specifications for the devices in this emissions unit are provided below.

9.m.  Emissions unit Paper Machine #5 (PM5-EU) emitting PM, PM₁₀, and VOC.

Pulp from the Deink and TPM/RMP mills are blended, screened and cleaned. A deculator (vacuum) is used to remove entrained air from the pulp. The blended pulp is sent to the headbox where, under pressure, the pulp is evenly distributed onto the forming section of the paper machine. At this point, the pulp consists of roughly 99% water and 1% pulp.

The paper machine uses woven fabrics with vacuum to form a sheet of paper (approximately 14% solids). The paper then enters the press section where felts, vacuum, and rolls are used to squeeze out more water. The fibers now begin to bond and form a smooth surface. The sheet at this time contains approximately 45% solids.

The sheet then enters the steam heated dryer section where the paper sheet is heated to approximately 150 - 180°F, causing water in the sheet to evaporate which is then exhausted by dyer hood fans. The paper sheet is now approximately 92% solids.

Once the sheet has left the dryer section, it is calendered, using steel rolls to increase smoothness and to even out the caliper. The sheet is then wound onto reels and transported to the winder. The winder is used to create a roll of paper based on customer requirements for width and diameter. Finished rolls are then wrapped and shipped by truck or rail car to the customer.

Additional information and specifications for this emissions unit are provided below.

9.n.  Emissions unit Paper Machine #6 (PM6-EU) emitting PM, PM₁₀, and VOC.
The process discussion for Paper Machine #6 is the same as for #5 above.

Additional information and specifications for this emissions unit are provided below.

9.o.  Emissions unit Steam Generator Unit #2 (SG2-EU) emitting PM, PM₁₀, SO₂/H₂SO₄, NO_x, CO, and VOC and consisting of the emissions device Heat Recovery Steam Generator Unit #2. The Steam Generator is fired with natural gas fuel and is used to produce steam that is used in the paper making processes. The supplemental heat source (CTG2) for this unit was removed in 2007.

9.p.  Emissions unit Thermal Mechanical Pulping (TMP-EU) emitting VOC and consisting of the following emission devices: TMP Refiner Line #1, TMP Refiner Line #5, TMP Refiner Line #6, RMP Refiner Line #2, RMP Refiner Line #3, Old Side Heat Recovery, and New Side Heat Recovery.

In the TMP process wood chips are cleaned and preheated with steam prior to being ground (refined) into pulp. In the RMP process the wood chips are cleaned prior to being refined. The difference between the RMP and TMP processes is that the TMP process utilizes high temperatures and pressurized steam to pre-heat the chips prior to refining, whereas the RMP process does not. The refiners, driven by large motors, provide the mechanical energy to convert the wood chips to pulp which is then screened and cleaned to remove contaminants and impurities. The pulp is then brightened using non-chlorine chemicals, concentrated, and stored for processing by the paper machines.

Additional information and specifications for the devices in this emissions unit are provided below.

9.q.  Emissions unit Unpaved Roads (UPR-EU) emitting fugitive PM and PM₁₀ from vehicular travel on the mill sites unpaved roads. Additional information and specifications for this emissions unit are provided below.

9.r.  Emissions unit Wastewater Treatment System (WWT-EU) emitting fugitive VOC and TRS and consisting of the following activities: Effluent Treatment System, Sludge Thickening, and the Pneumatic Sludge Handling Device.

Effluent Treatment System: During the paper making process large quantities of water are used. This mill draws water from the Willamette River, and removes the silt through a series of settling ponds and sand filters. After this filtered water is used in the boilers and the paper making process, it is treated in the Primary Clarifier to remove a large portion of the suspended solids. Effluent from the Primary Clarifier is then treated microbiologically in the secondary treatment system. The secondary treatment system consists of the North Lagoon, Activated Sludge Plant (ASP), Secondary Clarifier, South Lagoon and an outlet diffuser. Effluent first treated in the North Lagoon which is an aerated stabilization basin (ASB). Effluent from the North Lagoon flows into the Activated Sludge Plant and then into the Secondary Clarifier (Clarivac). The majority of the activated sludge is then returned to the ASP and the clarified effluent flows into the South Lagoon. The South Lagoon is an aerated stabilization basin. Effluent from the South Lagoon is discharged into the Willamette River through the outlet diffuser. A small percentage of activated sludge is returned to the Primary Clarifier where it is concentrated before being de-watered.

Sludge Thickening: The solids that are removed from the paper mill effluent treatment system are pumped to the sludge press building where the three sludge presses are used to reduce the water content of the sludge. The sludge has about a 3% solids content coming into the thickening process and about 47% solids content after being pressed.

Pneumatic Sludge Handling Device: The dewatered sludge is pneumatically conveyed to the hog fuel storage area.

Additional information and specifications for the devices in this emissions unit are provided below.

Control Devices

10.  Control devices at this facility are as follows:

11.  Categorically insignificant activities include the following:

•  Constituents of a chemical mixture present at less than 1% by weight of any chemical or compound regulated under Divisions 20 through 32 of this chapter, or less than 0.1% by weight of any carcinogen listed in the U.S. Department of Health and Human Service's Annual Report on Carcinogens when usage of the chemical mixture is less than 100,000 pounds/year

•  Evaporative and tail pipe emissions from on-site motor vehicle operation

•  Distillate oil, kerosene, and gasoline fuel burning equipment rated at less than or equal to 0.4 million Btu/hour

•  Natural gas and propane burning equipment rated at less than or equal to 2.0 million Btu/hour

•  Office activities

•  Food service activities

•  Janitorial activities

•  Personal care activities

•  Groundskeeping activities including, but not limited to building painting and road and parking lot maintenance

•  On-site laundry activities

•  On-site recreation facilities

•  Instrument calibration

•  Maintenance and repair shop

•  Automotive repair shops or storage garages

•  Air cooling or ventilating equipment not designed to remove air contaminants generated by or released from associated equipment

•  Refrigeration systems with less than 50 pounds of charge of ozone depleting substances regulated under Title VI, including pressure tanks used in refrigeration systems but excluding any combustion equipment associated with such systems

•  Bench scale laboratory equipment and laboratory equipment used exclusively for chemical and physical analysis, including associated vacuum producing devices but excluding research and development facilities

•  Temporary construction activities

•  Warehouse activities

•  Accidental fires

•  Air vents from air compressors

•  Air purification systems

•  Continuous emissions monitoring vent lines

•  Demineralized water tanks

•  Pre-treatment of municipal water, including use of deionized water purification systems

•  Electrical charging stations

•  Fire brigade training

•  Instrument air dryers and distribution

•  Process raw water filtration systems

•  Blueprint making

•  Routine maintenance, repair, and replacement such as anticipated activities most often associated with and performed during regularly scheduled equipment outages to maintain a plant and its equipment in good operating condition, including but not limited to steam cleaning, abrasive use, and woodworking

•  Electric motors

•  Storage tanks, reservoirs, transfer and lubricating equipment used for ASTM grade distillate or residual fuels, lubricants, and hydraulic fluids

•  On-site storage tanks not subject to any New Source Performance Standards (NSPS), including underground storage tanks (UST), storing gasoline or diesel used exclusively for fueling of the facility's fleet of vehicles

•  Natural gas, propane, and liquefied petroleum gas (LPG) storage tanks and transfer equipment

•  Pressurized tanks containing gaseous compounds

•  Fire suppression and training

•  Paved roads and paved parking lots within an urban growth boundary

•  Hazardous air pollutant emissions of fugitive dust from paved and unpaved roads except for those sources that have processes or activities that contribute to the deposition and entrainment of hazardous air pollutants from surface soils

•  Health, safety, and emergency response activities

•  Emergency generators and pumps used only during loss of primary equipment or utility service

•  Non-contact steam vents and leaks and safety and relief valves for boiler steam distribution systems

•  Non-contact steam condensate flash tanks

•  Non-contact steam vents on condensate receivers, deaerators and similar equipment

•  Boiler blowdown tanks

•  Industrial cooling towers that do not use chromium-based water treatment chemicals

•  Ash piles maintained in a wetted condition and associated handling systems and activities

•  Oil/water separators in effluent treatment systems

•  Combustion source flame safety purging on startup

•  Broke beaters, pulp and repulping tanks, stock chests and pulp handling equipment, excluding thickening equipment and repulpers

•  Stock cleaning and pressurized pulp washing, excluding open stock washing systems

•  White water storage tanks

EMISSION LIMITS AND STANDARDS, TESTING, MONITORING, AND RECORDKEEPING

Oregon Administrative Rules

12.  The following Chapter 340 Oregon Administrative Rules that have specific requirements (e.g., emission limits or standards, monitoring, recordkeeping, or reporting requirements) have been determined to be applicable to this facility. The “Oregon Title V Monitoring and Testing Guidance” was used to determine the periodic monitoring schedules and testing requirements that the source will use to assure compliance with the listed standard. Note: No monitoring is being required devices/processes that are not operated during the monitoring period.

12.a.  111-020(2)(c), and 40CFR 279.1 [Used oil requirement]

The used oil that is generated from activities on the mill site and burned in the boilers must meet the definition of used oil. The source must conduct an analysis of a representative sample at least once per year.

12.b.  208-0110 [General Visible Emissions Limit]
The 20% opacity limit for visible emissions applies to all emissions units and activities at the facility, including categorical and aggregate insignificant activities.

B67-EU, CG1-EU, and SG2-EU

Because these are natural gas combustion sources, no monitoring is being required to demonstrate compliance with this requirement.

B9-EU

A VE test must be conduct at least once per calendar quarter unless natural gas is the only fuel combusted during the quarter, then no monitoring is required.

B10-EU

The source must continually monitor visible emissions with a continuous opacity monitor (COM) and take corrective action if a 6-minute block opacity reading is greater than or equal to 7.5%.

CHS-EU

A ten year history of visible emissions tests found no visible emissions present from the emission devices in emissions unit CHS-EU. As such, the requirement to conduct periodic visible emissions tests is being replaced by a monthly inspection and maintenance program.

PM5-EU, PM6-EU, DI-EU, TMP-EU, and WWT-EU

Because the activities associated with these emission units do not create visible emissions, no periodic VE monitoring is being required. However, if VE testing is conducted, then modified EPA Method 9 must be used. The source is required to investigate, respond, and maintain records of air quality related complaints regarding these emission units in accordance with Condition 7 of the permit.

CSP-EU, HFSP-EU, MH-EU, and UPR-EU

Because these emission units are fugitive dust sources, no periodic VE monitoring is being required. The source is required to comply with the Fugitive Emissions Reduction plan and it is required to investigate, respond, and maintain records of air quality related complaints regarding these emission units in accordance with Condition 7 of the permit.

12.c.  208-0210 [Fugitive Emissions]
Since this facility is located in a special control area, the requirement to minimize fugitive emissions by taking preventative measures applies. The source must: a) Comply with the Fugitive Emissions Reduction Plan, b) Promptly investigate fugitive emission complaints and maintain a record of the complaints and actions taken to resolve within 5 business days, and c) Maintain a telephone number capable of receiving complaints 24-hours per day. The telephone number must be posted at the front gate and be visible from the public street. In addition, the number must be published in the local paper annually or the company must maintain a web site that contains complaint contact information.

12.d.  208-0300 [Nuisance Rule]
Air contaminants from this facility must not cause a nuisance. This requirement is only enforceable by the state. The source is required to promptly investigate air quality related nuisance complaints and maintain a record of the complaints and actions taken to resolve within 5 business days. It must also maintain a telephone number capable of receiving complaints 24-hours per day. The telephone number must be posted at the front gate and be visible from the public street. In addition, the number must be published in the local paper annually or the company must maintain a web site that contains complaint contact information.

12.e.  208-0450 [PM Fallout]
The source is not allowed to emit particulate matter that is greater than 250 microns in size at sufficient duration or quantity as to create an observable deposition upon the real property of another person. This rule is only enforceable by the state. The source is required to promptly investigate fallout complaints and maintain a record of the complaints and actions taken to resolve within 5 business days. It must also maintain a telephone number capable of receiving complaints 24-hours per day. The telephone number must be posted at the front gate and be visible from the public street. In addition, the number must be published in the local paper annually or the company must maintain a web site that contains complaint contact information.

12.f.  218-0080(8) [Fuel Restrictions]

B67-EU

A 1991 SO₂ air quality modeling analysis showed that violations of the ambient air quality standards may occur when Bunker C oil is combusted in Boilers #6 and #7. As such, the source has agreed to only combusted natural gas fuel in emissions unit B67-EU. The permittee must maintain records of the types of fuels combusted in emissions unit B67-EU.

B9-EU

To avoid being classified as an incinerator, the amount of miscellaneous fuels that may be combusted in Boiler #9 is limited to no more than 30% of the total heat input value used by this boiler on an annual basis. Records must be maintained demonstrating compliance with this fuel restriction limit.

B10-EU

To avoid being classified as an incinerator, the amount of miscellaneous fuels that may be combusted in Boiler #10 is limited to no more than 30% of the total heat input value used by this boiler on an annual basis. Records must be maintained demonstrating compliance with this fuel restriction limit.

12.g.  222-0040 through 0043 [Plant Site Emission Limits]
Plant site emission limits (PSEL) are required for all regulated pollutants that are emitted at levels exceeding the de minimis level for that pollutant. The permittee must demonstrate compliance with the emission limits listed in the permit for PM, PM₁₀, CO, NO_x, SO₂, VOC, TRS, H₂SO₄, and Pb by calculating the facility wide emissions for each pollutant for each consecutive 12-month period by the end of the following month and comparing the results to the PSEL.

12.h.  226-0210(1)(a)  [PM < 0.2 grain/dscf ]

No source constructed prior to June 1, 1970 is allowed to emit particulate matter emissions in excess of 0.2 grains/dry standard cubic foot. This rule applies to emissions unit PM5-EU because it was installed in July 1968

PM5-EU

Because prior compliance emissions testing has demonstrated that PM emissions from PM5-EU were substantially less than the applicable standard, no further testing is being required at this time. Historically, no visible emissions have been observed from emissions unit PM5-EU, as such, monitoring will be based on recordkeeping. The source is required to investigate, respond, and maintain records of air quality related complaints regarding this emissions unit in accordance with Condition 7 of the permit.

12.i.  226-0210(1)(b)  [PM < 0.1 grain/dscf]

No source constructed on or after June 1, 1970 is allowed to emit particulate matter emissions in excess of 0.1 grains/dry standard cubic foot. This rule applies to emissions units CHS-EU and PM6-EU.

CHS-EU

Because prior compliance emissions testing has demonstrated that the PM emissions from CHS-EU were substantially less than the applicable standard, further testing is not being required at this time. The permittee must conduct a monthly inspection and maintenance program to demonstrate continuing compliance with the requirement.

PM6-EU

Because prior compliance emission testing has demonstrated that PM emissions from PM6-EU were substantially less than the applicable standard, further testing is not being required at this time. Historically, no visible emissions have been observed from emissions units PM6-EU, as such, monitoring will be based on recordkeeping. The source is required to investigate, respond, and maintain records of air quality related complaints regarding this emissions unit in accordance with Condition 7 of the permit

12.j.  226-0310 [Device Process Weight Emission Limit]

This rule is applicable to emissions units PM5-EU, PM6-EU, and CHS-EU. Particulate matter emissions from these units must not exceed the limits shown in Table 1 to this rule. Because prior emissions testing has demonstrated that PM emissions from these emissions units were substantially less than the applicable standard, further testing is not being required at this time.

Historically, no visible emissions have been observed from emissions units PM5-EU and PM6-EU; as such, monitoring will be based on maintaining a complaint log in accordance with permit Condition 7 for these emissions units. To demonstrate continuing compliance for CHS-EU, a monthly inspection and maintenance program must be performed.

12.k.  228-0100 and 0110 [Fuel Oil Sulfur Limits]
The rules limiting the sulfur content of fuel oils burned to less than 0.3% for #1 distillate oil, 0.5% for #2 distillate oil, and 1.75% for residual oil and used oils apply to this facility. The amount of sulfur in each batch of oil received is required to be monitored by either obtaining a sulfur content certificate from the vendor or conducting a laboratory analysis of a representative sample.

12.l.  228-0200 [SO₂ Emission Standards for Fuel Burning Devices]

This rule limits the amount of SO₂ emission that can be emitted from a boiler based on the type of fuel(s) combusted (liquids and/or solids). It applies to fuel burning equipment installed after January 1, 1972 that burn liquid and/or solid fuels and have a heat input rating of 150 – 250 million Btu/hour or heat inputs greater than 250 million Btu/hour. Boiler #9 was installed in July 1975 and is rated at 285 million Btu/hour heat input. Boiler #10 was installed in December 1980 and is rated at 567.5 million Btu/hour heat input. Thus the portion of the rule that applies to units greater than 250 million Btu/hour heat input applies to Boiler #9 and Boiler #10. As such, SO₂ emissions from Boilers #9 or Boiler #10 must not exceed 0.8 pound per million Btu heat input when burning liquid fuel and 1.2 pounds per million Btu when burning solid fuels. Compliance with these emission limits are determined by material balance calculations based on the sulfur content of the fuel burned.

12.m.  228-0210(1)(a)  [PM < 0.2 grains/dscf @ 12% CO₂ Limit]
Particulate matter emissions from fuel burning equipment installed prior to June 1, 1970 must not exceed 0.2 grains/dry standard cubic foot corrected to 12% CO₂ content. Boilers #6 and #7 were installed in 1967 and are vented to a common stack.

B67-EU

Because Boilers #6 and #7 are natural gas combustion sources, no monitoring is being required to demonstrate compliance with this requirement. If a test for particulate matter is conducted, ODEQ Method 5 must be used.

12.n.  228-0210(1)(b)  [PM < 0.1 grains/dscf @ 12% CO₂ Limit]

Particulate matter emissions from fuel burning equipment installed on and after June 1, 1970 must not exceed 0.1 grains/dry standard cubic foot corrected to 12% CO₂ content. This rule applies to emissions units B9-EU, B10-EU, CG1-EU, and SG2-EU. Boiler #9 was installed in July 1975, Boiler #10 was installed in December 1980, and the Cogeneration System 1 and the Steam Generating Unit 2 were installed in 2003.

B9-EU

Boiler #9 must be tested for particulate matter emissions using ODEQ Method 5 at least once prior to December 1, 2011. The testing requirement is not applicable if Boiler #9 is operated fewer than 120 consecutive days during the permit term.

The residual oxygen in Boiler #9 must be monitored continuously and corrective action taken if the value is less than or equal to 3% except during periods of startup or shutdown.

The liquid flow rate and the pressure drop for the wet scrubber control device (B9-WS) must be continuously monitored and corrective action taken if the liquid flow rate value is less than 35 gallons per minute or the pressure drop is less 7 inches of water.

Yearly inspections of the multiclones (B9-MC) and wet scrubber (B9-WS) control systems must be conducted for wear, plugging, abrasion, and integrity and repairs made as needed.

B10-EU

Boiler #10 must be tested for particulate matter emissions using Oregon Method 5 at least once prior to December 1, 2011. The testing requirement is not applicable if Boiler #10 is operated fewer than 120 consecutive days during the permit term.

The opacity of the exhaust gas must be continuously monitored and corrective action taken if the value of any 6-minute block average equals or exceeds 7.5%.

The residual oxygen in Boiler #10 must be monitored continuously and corrective action taken if the value is less than or equal to 3% except during periods of startup or shutdown.

Yearly inspections of the multiclones (B10-MC) and electrostatic precipitator (B10-ESP) control systems must be conducted for wear, plugging, abrasion, and integrity and repairs made as needed.

CG1-EU and SG2-EU

Co-generation System #1 and Steam Generator Unit #2 combust natural gas only, thus no monitoring is being required for these units to demonstrate compliance with this rule.

Air Contaminant Discharge Permit (ACDP) Requirements

13.  The following ACDP Requirements have been incorporated into this Title V permit.

13.a.  6/13/95 ACDP Addendum 2, Condition 4 :
The amount of tire derived fuel (TDF) that may be combusted in emissions unit Boiler #9 must be less than or equal to 1% by weight of the total solid fuels burned on an annual basis. In prior permits, this condition was applicable to both Boiler #9 and Boiler #10 because the fuel feed system at the time could not limit which boiler the TDF would be delivered to. Initial testing with TDF at Boiler #9 demonstrated that if the solid fuel mix contained more than 1% TDF, the boiler exceeded particulate matter emission standards. The permittee must maintain records on a monthly basis of the amount of TDF combusted in Boiler #9.

The amount of fiber based fuel (FBF) burned in emissions unit B10-EU must less than or equal to 13.7% by weight of the total amount of solid fuels burned on an annual basis. The permittee must maintain records on a monthly basis of the amount of FBF combusted in Boiler #10

The amount of creosoted treated wood fuel (CTWF) burned in emissions unit B10-EU must less than or equal to 50% by weight of the total amount of solid fuels burned on an annual basis. The permittee must maintain records on a monthly basis of the amount of CTWF combusted in Boiler #10

14.  PSD Permit (PSD-X80-03) contained opacity and pollutant emission limits for emissions unit B10-EU.

14.a.  Visible emissions from Boiler #10 must not equal or exceed 10% opacity (6-minute average). The permittee is required to operate and maintain a continuous opacity monitor and maintain records of the 6-minute block opacities.

14.b.  Particulate matter emissions from Boiler #10 must be equal to or less than 0.04 grains/dscf corrected to 12% CO₂.

Boiler #10 must be tested for particulate matter emissions using EPA Method 5 at least once prior to December 1, 2011. The testing requirement is not applicable if Boiler #10 is operated fewer than 120 consecutive days during the permit term.

The opacity of the exhaust gas must be continuously monitored and corrective action taken if the value of any 6-minute block average equals or exceeds 7.5%.

The residual oxygen in Boiler #10 must be monitored continuously and corrective action taken if the value is less than or equal to 3% except during periods of startup or shutdown.

Yearly inspections of the multiclones (B10-MC) and electrostatic precipitator (B10-ESP) control systems must be conducted for wear, plugging, abrasion, and integrity and repairs made as needed.

14.c.  Boiler #10 must not exceed the following emission rates:

•  PM < 86.5 pounds/hour, daily average

•  CO < 220 pounds/hour, daily average

•  NO_X < 769 pounds/hour, daily average

•  VOC < 220 pounds/hour, daily average

The permittee has demonstrated that the emission rates of these pollutants from Boiler #10 when operating at maximum capacity is less than the specified PSD limit. Thus no further monitoring is being required to demonstrate compliance with these limits. Note: Boiler #10 is being tested for PM emissions to demonstrate compliance with other requirements.

Federal Requirements

15.  The applicability of various federal requirements is as follows:

15.a.  NSPS (40 CFR Part 60)

Subpart D [8/17/71 NSPS for Fossil-Fuel-Fired Steam Generators rated at more than 250 million Btu per hour heat input] is not applicable to the steam generating units at this facility.

•  Boiler #9 was installed in 1975, but has a fossil fuel heat input rating of 223 million Btu per hour.

•  Boiler #10 was installed in 1980, but has a fossil fuel heat input rating of 249 million Btu per hour. Note: Boiler No. 10 has two auxiliary fossil fuel burners that are used to start the boiler and to maintain operating temperature as needed. These burners primarily consume natural gas. However, they can be made to fire distillate oil when the supply of natural gas is interrupted. There is also an “in duct” burner (fired by natural gas only) that heats under-grate air. The flow of fossil fuel to the three burners is physically limited such that no more than 249 million Btu per hour can be supplied. The physical limitation was specifically designed to avoid this NSPS standard.

•  Heat Recovery Steam Generator #1 was installed in 2003, but has a heat input rating of 250 million Btu/hour.

•  Steam Generator Unit #2 was installed in 2003, but has a heat input rating of 250 million Btu/hour.

Subpart Db [Industrial-Commercial-Institutional Steam Generating Units] is applicable to units installed after 6/19/84 with a heat input capacity greater than 100 million Btu/hour.

•  Heat Recovery Steam Generator #1 (HRSG1) and Heat Recovery Steam Generator # 2 (HRSG2) are each rated at 250 million Btu/hour heat input and were installed in 2003. As such, the requirements of Subpart Db apply to these units.

40 CFR 60.44b(a)(4)(i) requires that each unit meet a NO_X emission limit of 0.20 lb/MMBtu heat input. NSPS compliance testing conducted in September 2005 demonstrated that the actual NO_X emissions from each unit were substantially less than the standard (see Page 49 of this report). As such, no further testing is being required at this time.

•  Boiler #6 was installed in 1967, prior to the applicability date, and no modifications have been made to the unit.

•  Boiler #7 was installed in 1967, prior to the applicability date, and no modifications have been made to the unit.

•  Boiler #9 was installed in 1975, prior to the applicability date, and no modifications have been made to the unit.

•  Boiler #10 was installed in 1980 and modified in June 1991 when the wet scrubber was replaced by the electrostatic precipitator due to public comments of black rain from the wet scrubber. Although the change in control devices resulted in a SO₂ emissions increase from the boiler, the replacement was not considered a modification subject to the standard. 40 CFR 60.14(e)(5) states the following shall not, by themselves, be considered modifications under this part: “the addition or use of any system or device whose primary function is the reduction of air pollutants, except when an emission control system is removed or is replaced by a system which the Administrator determines to be less environmentally beneficial.”

During a July 1991 source test, it was determined the Boiler #10 exceeded the permitted SO₂ PSEL because of the replacement of the wet scrubber with an electrostatic precipitator (ESP). The Depart

ment required the company to perform computer modeling before the 11/25/92 ACDP was issued to ensure that the SO₂ emissions from Boilers #9 and #10 were not exceeding the ambient air quality standards. The modeling results predicted that no exceedances of the ambient air quality standards would occur as a result of the increased SO₂ emissions from Boiler No. 10. Therefore, the Department increased the SO₂ PSEL for Boiler #10 by using the credits from the shutdown of the sulfite mill. As a result of using the credits, the facility wide PSEL for SO₂ was not increased in the ACDP issued on 11/25/92. Therefore, the Department determined that the replacement of the wet scrubber with the ESP was an environmentally beneficial project because of the reduction in particulate matter emissions and that the modification did not make the unit subject to New Source Performance Standards.

Subpart Dc [Small Industrial-Commercial-Institutional Steam Generating Units] is applicable to small steam generating units installed after 6/9/89 with a heat input capacity of less than or equal to 100 million Btu/hour and greater than or equal to 10 million Btu/hour.

All steam generating units at this facility have heat input ratings greater than 100 million Btu/hour, thus this rule is not applicable.

Subpart GG [Stationary Gas Turbines]

This rule is applicable to stationary gas turbines installed after 10/03/77 with a heat input at peak load of greater than or equal to 10 million BTU/hour. Combustion Turbine #1 (CTG1) was installed in 2003, and has a heat input ratting of 465 million Btu/hour, thus Subpart GG is applicable to this unit.

NSPS compliance testing for NO_X emissions conducted in July 2004 demonstrated that CTG1 was well within the standard (see page 49 of this report). As such, no further testing is being required at this time.

Subpart YYYY [Stationary Combustion Turbines] is applicable to units installed after 2/18/05 with a heat input rating of greater than or equal to 10 million Btu/Hour.

This rule is not applicable to Combustion Turbine #1 because it was installed in 2002.

15.b.  NESHAP

The following National Emissions Standards for Hazardous Air Pollutants (NESHAP), 40 CFR Parts 61 and 63, requirements are applicable or not applicable to this facility for the reasons stated.

•  Part 61, Subpart E [National Emission Standards for Mercury]

The Department has determined that while these standards do apply to the Hogged Fuel Dryer (HFD), they do not apply to emissions units B9-EU and B10-EU. Correspondence between the former owner of the facility (Smurfit Newsprint Corp.) and EPA Region 10 indicates that the EPA believes that this standard also applies to the boilers, which burn the sludge. The EPA states in a letter dated 06/23/95 that 40 CFR Part 61, Subpart E applies to the hogged fuel/sludge dryer and Boilers #9 and #10. In a letter dated 07/12/95, the company states that the boilers do not meet the definition of “incinerator” because the primary purpose of combusting the sludge is energy recovery. The EPA responded in a letter dated 08/07/95 and stated that their previous determination that the NESHAP applies to the boilers is still valid.

The Department disagrees with the EPA interpretation that the NESHAP applies to the boilers. The NESHAP states that it applies to stationary sources that incinerate or dry wastewater treatment plant sludge. The Department does not believe that Boilers #9 and #10 are incinerators because the primary purpose for burning the sludge is heat recovery, not reducing either volume or weight. Therefore, the Department is only including the NESHAP as an applicable requirement for the sludge dryer.

•  Part 63, Subpart S [Pulp and Paper Industry] does not apply to this facility.

SP Newsprint Co. is exempt from these requirements because the facility uses mechanical, thermo-mechanical, and deinking processes to produce pulp and the pulp is brightened without the use of chlorine or chlorinated compounds. Pursuant to 63.440(b)(2) the affected source for mechanical pulpers is the bleaching system only. Pursuant to 63.445(a) bleaching systems that do not use chlorine or chlorinated compounds are exempted from the bleaching requirements.

•  Part 63, Subpart DDDDD [Boilers and Process Heaters]

In July 2007, the federal courts vacated this rule in its entirety. The DEQ is removing the condition in the Title V permit that incorporated this rule by reference. The DEQ will reopen this permit to incorporate appropriate requirements at such time as the EPA reissues the rule, or the state makes a case-by-case MACT determination for this facility.

CAM

15.c.  40 CFR Part 64 [Compliance Assurance Monitoring (CAM)]

The CAM rule applies to emissions units B9-EU and B10-EU. Compliance Assurance Monitoring for these units is as follows:

B9-EU
The source must operate and maintain continuous monitors to measure the pressure drop and liquid flow rate values of the particulate matter control device (B9-WS) and take corrective action if a value is outside the established range. At this time, the pressure drop must be equal to greater than 7.0 inches of water (1-hour average), except when Boiler #9 is operating at less than 25,000 pounds of steam per hour, and the liquid flow rate must be equal to or greater than 35.0 gallons per minute (1-hour average).

B10-EU

The source must operate and maintain a continuous opacity monitor to measure visible emissions at the exhaust point of Boiler #10 and take corrective action if a 6-minute average value is equal to or greater than 7.5%. The opacity monitor is being used in lieu of monitoring the physical operating parameters associated with the particulate matter control device (B10-ESP).

Accidental Release

15.d.  40 CFR Part 68
The source has certified that the facility is not subject to the Accidental Release Rule, which requires a risk management plan for toxic and flammable substances releases.

16.  Insignificant Emission Units As identified earlier in this Review Report, this facility has insignificant emissions units (IEUs). For the most part, the standards that apply to IEUs are for opacity (20% limit) and particulate matter (0.1 gr/dscf limit). The Department does not consider it likely that IEUs could exceed an applicable emissions limit or standard because IEUs are generally equipment or activities that do not have any emission controls (e.g., small natural gas fired space heaters) and do not typically have visible emissions. Since there are no controls, no visible emissions, and the emissions are less than one ton per year, the Department does not believe that monitoring, recordkeeping, or reporting is necessary for assuring compliance with the standards.

PLANT SITE EMISSION LIMITS

17.  Provided below is a summary of the baseline emissions rate, netting basis, and plant site emission limits.

(a) Unassigned emissions reduction rule (OAR 340-222-0045).

17.a.  The baseline emission rate calculations and netting basis determinations are shown in Appendix A.

The previous netting basis for particulate matter emissions has been changed from what were shown in the last permit renewal (1/1/03) to correct an emission inventory error. The particulate matter emissions from the #10 Boiler were previously calculated based on EPA Method 5 test results which only include the particulate matter captured in the “front half” (“filterable PM”) of the sampling train. The PSEL and Netting Basis are based on total emissions (i.e. material captured in both the front (“filterable PM”) and back (“condensible PM”) portions of the sampling train). As such, the 1980 PSD (Boiler #10 installation) adjustment to the Baseline Emission Rate for particulate matter has been increased from 237 tons/year to 588 tons/year.

As shown in the following tables, a review of the 1980 air quality modeling analysis adjusted to account for the corrected emissions from Boiler #10 demonstrates that the ambient air quality standards and PSD increments requirements are met. It should be noted that the original air quality modeling analysis was performed using screening meteorological data assumptions rather than specific meteorological data for the Newberg area which resulted in very conservative air quality impact values. If the modeling had employed actual meteorological data, the air quality analysis results would be expected to be at considerably lower concentrations.

NATIONAL AMBIENT AIR QUALITY STANDARDS (NAAQS)

PREVENTION OF SIGNIFICANT DETERIORATION (PSD) INCREMENT CONSUMPTION

17.b.  The calculation detail sheets for the proposed PSEL are shown in Appendix B. The changes in the PSEL are due to the following:

•  An approximately 3% increase in the plant’s production capacity due to proposed upgrades to the paper machines.

•  The emission factor for calculating particulate matter emissions from Boiler #10 when combusting solid fuels was updated and corrected based on an analysis of Oregon Method 5 source test results.

•  A proposed ventilation project for the Deink Plant building will result in an increase in the amount of particulate matter emissions being vented to the atmosphere.

•  An increase in the amount of tire derived fuel allowed to be burned in Boiler #10 and the addition of a new solid fuel (dried biosolids) that will be burned in the boiler.

•  The removal of the Combustion Turbine Generator #2 from service.

18.  In addition to the PSEL, the permit includes the following:

18.a.  Pursuant to OAR 340-222-0045(5), the unassigned emissions for PM and PM₁₀ will be established again and reduced upon the following permit renewal to no more than the SER for each pollutant.

18.b.  The emission reduction credits are derived from the permanent shut down of the Combustion Turbine Generator #2 on May 14, 2007. Emission reduction credit calculation details are found in Appendix C. The stack parameters for this emissions device are as follows:

•  Stack Height = 150 feet

•  Stack Diameter = 11.5 feet

•  Stack Gas Flow Rate = 345,000 acfm

•  Stack Gas Temperature = 309ºF

If not used prior to May 17, 2017, the credits will expire and will become unassigned emissions.

SIGNIFICANT EMISSION RATE

19.  The proposed PSELs for VOC, SO₂, H₂SO₄, and TRS are greater than the previous netting basis as shown below. However, no further air quality analysis is needed because the increases are less than the applicable significant emission rate.

HAZARDOUS AIR POLLUTANTS

20.  Hazardous air pollutants are detailed in Appendix B, Pages 14-16.

OTHER PERMITS

21.  Other permits issued or required by the Department for this source include an NPDES Wastewater Discharge Permit (No. OR 0000558) and a Storm Water Discharge Permit (1200Z). The source is also registered with the Department as a Conditionally Exempt Small Quantity Hazardous Waste Generator.

COMPLIANCE HISTORY

Inspections

22.  During the prior permit term, the facility was inspected on 8/19/03, 8/24/04, 7/20/05, 8/18/06, and 8/14/07 and was found to be in compliance with Department regulations and permit conditions.

Complaints

23.  SP Newsprint received and responded to a total of 21 air quality related complaints during prior permit period. Of these complaints: 18 were dust related complaints of which 2 were determined to be not mill related; one was an odor complaint that was not mill related; one was a complaint concerning house paint failure that was determined to be not mill related; and one complaint regarding noise was received but investigation by mill staff was unable to determine the source. In each case of a valid complaint, actions were taken to rectify operational problems or corrective actions were implemented such as watering.

Enforcement

24.  The following enforcement actions were taken by the Department against SP Newsprint in the prior permit term.

24.a.  AQ/V-WRS-03-156 – A notice of noncompliance was issued on 11/14/03 for failure to perform weekly cleaning activities during the week of October 13, 2003.

24.b.  AQ/V-WRS-04-131 – A notice of noncompliance was issued on 7/21/04 for failing to notify the Department in a timely manner of excess emission events that occurred on July 5 and July 7, 2004.

24.c.  AQ/V-WRS-04-191 – A notice of noncompliance was issued on 10/18/04 for failing to apply water when the chip dump blower system was being operated on 9/30/04.

SOURCE TEST RESULTS

25.  Source test results for various operational devices are summarized in the following tables.

Boilers #6 & 7 Source Test Results

Boiler #9 Source Test Results

Boiler #10 Source Test Results

Combustion Turbine #1

HRSG1 and HRSG2

Pneumatic Chip Handling System Source Test Results

Deink Plant Source Test Results

Paper Machine #5 Source Test Results

Paper Machine #6 Source Test Results

Refiner Mill Source Test Results

PUBLIC NOTICE

26.  This permit will be put out on public notice from December 26, 2007, to January 31, 2008. Comments may be submitted in writing during the comment period. The Department will hold a public hearing if requested by 10 or more individuals or one person representing a group of 10 or more individuals. After the comment period and hearing, if requested, the Department will review the comments and modify the permit as may be appropriate. A proposed permit will then be sent to EPA for a 45 day review period. The Department may request and EPA may agree to an expedited review of 5 days if there were no substantive or adverse comments during the comment period. In any event, the public will have 105 days (45 day EPA review period plus 60 days) from the date the proposed permit is sent to EPA to appeal the permit with EPA. The permit will be issued following EPA’s review.

During the public comment period the Department received two comments: one from the Northwest Pulp and Paper Association (NWPPA) in support of the permit as drafted and one from SP Newsprint requesting minor corrections to some of the permit conditions. SP Newsprint’s comments and the Department’s responses are shown in the following table.