FACILITY PROFILE. Irving Oil Refining G.P. Saint John Refinery

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1 FACILITY PROFILE Irving Oil Refining G.P. Saint John Refinery Prepared by: Impact Management Branch New Brunswick Department of Environment & Local Government September 2014

2 TABLE OF CONTENTS BACKGROUND PROCESS DESCRIPTION AIR POLLUTION CONTROL POTENTIAL AIR QUALITY CONTAMINANTS POTENTIAL IMPACTS OF AIR EMISSIONS AIR QUALITY COMPLIANCE AND ENFORCEMENT PUBLIC OUTREACH CONTACTS REFERENCES GLOSSARY 2

3 BACKGROUND The Irving Oil Refinery, built on a plot of farmland in 1959 in east Saint John, officially opened on July 20, At the time, the refinery was designed to process 38,500 barrels of crude oil per day (BPD). Two new process areas, constructed in 1976, resulted in the refinery becoming the largest in Canada with a current reference crude rate of 313,000 BPD. In order to prepare for the requirement for cleaner burning fuels, the availability of natural gas as well as potential changes in the supply of crude oils, Irving Oil Refining G.P. (formerly Irving Oil Limited) registered the Refinery Upgrade Project (1) under the Environmental Impact Assessment (EIA) Regulation in March of This project, which the Minister allowed to proceed under specific conditions (2) on August 13, 1998, involved the construction of eight new units, of which three were petroleum production units and five were environmental control units. These are discussed in the sections on Process Description and Air Pollution Control. By the end of 2001, all new units had been commissioned. The upgrade did not increase the nameplate capacity of the refinery as the design crude processing capacity, on which the nameplate capacity is based, did not increase. The Irving Oil Refining G.P. refinery produces a range of fuels for transportation (ultra-low sulphur gasoline, ultra-low sulphur diesel, jet fuel) and combustion applications (home heating oil, kerosene, Bunker C). Other fuels produced for use in more specialized combustion and transportation applications include butane and propane. The heaviest components of crude oil are used in asphalt, which is sold for paving. With the availability of natural gas from the Sable Island Gas Field, the demand for heavy fuels like Bunker C, which have traditionally been used for heating, electricity generation and marine transportation, is diminishing. Product demand continues to be strong for cleaner fuels for use in transportation and combustion applications. The refinery upgrade allowed the refinery to meet current and anticipated product demand for cleaner fuels and environmental requirements. Over the next few years, Irving Oil plans to complete some reliability and optimization projects during future maintenance turnarounds. These projects will likely involve replacing and improving components within existing units to improve their efficiency. The improvements may increase the volumes of certain products being produced, but it is expected that emissions will remain within the approved limits. PROCESS DESCRIPTION The refinery consists of units for distillation, cracking, reforming (molecular rearrangement), product treating, steam and hydrogen production, sulphur recovery, and tanks for blending and product storage. Below are brief descriptions of the process operations: 3

4 Distillation The purpose of crude oil refining is to convert the diverse mixture of petroleum hydrocarbons present in the crude oil, into component streams having the best use and marketability. Crude oil contains a mixture of hydrocarbons of various chemical compositions and boiling points as well as impurities, such as brine and sulphur and nitrogen compounds. This mixture contains a range of petroleum hydrocarbons from the lightest, methane, which is the primary constituent of natural gas, to the heaviest residues, with high molecular weights, that are used in paving asphalt. Between these are a series of hydrocarbons that are separated for use in gasoline, jet fuel, diesel fuel, home heating oil and heavy fuel oils. The first step in the refining process, following removal of brine, is to separate the hydrocarbons present in the crude oil into distinct boiling ranges. Some of the separated products may be used directly in saleable products while others must be processed further in order to make the most of their inherent value and to meet product specifications. The separation process, known as distillation, takes place in a distillation column as shown in Figure 1. The crude oil is first heated to temperatures above 700 F after which it is fed to a distillation column containing a series of perforated trays. Due to differences in the boiling points of the hydrocarbons, the crude oil vapours condense on the trays at different levels within the distillation column. The lower boiling point hydrocarbons (heavier products) condense first and are withdrawn near the bottom of the column. As the crude oil vapours move up the column, progressively lighter fractions condense and are withdrawn. Those fractions that do not condense are withdrawn as a gas at the top of the column. The heavy ends, those hydrocarbons that are too heavy to boil off in the first distillation column, collect in the bottom of the column and are withdrawn and sent to a second distillation column, which operates under a vacuum. Under vacuum the hydrocarbons boil at lower temperatures and gas oils, which could not be vaporized in the first column, move up through the column and are separated out. The heaviest (bottom) products are used in asphalt. The separated gas oils are further processed in the cracking units as described under Cracking. 4

5 Figure 1: Schematic of Crude Oil Distillation Column The refinery operates two crude oil distillation units: Crude Unit No. 3 (146,000 BPD) constructed in Crude Unit No. 4 (155,000 BPD) constructed in 1999 and commissioned in Cracking Following distillation, the gas oils, which represent approximately half of the crude, are broken into smaller molecules in processes referred to as cracking operations. Cracking employs a catalyst, which is a material that is used to promote a reaction but which is not consumed in the reaction. The catalyst is used either to speed up the reaction or to allow it to occur at a lower temperature, which renders the process more energy efficient. Following are the three cracking units at the refinery: Residue Fluid Catalytic Cracking Unit (RFCCU) (90,000 BPD) where residual oil (high molecular weight "residual" oil) is cracked and can be separated into fractions including fuel gas, propane, propylene, butane, butylene, gasoline, diesel and decant oil. 5

6 Fluid Catalytic Cracking Unit (FCCU) (25,000 BPD) where vacuum gas oils are cracked and separated into fractions that form gasoline, diesel and liquefied petroleum gas (LPG); and Visbreaker (20,000 BPD) where residue from the vacuum tower of the crude units is cracked at high temperatures to make gasoline and diesel fuels. Molecular Rearrangement Light molecules in the gasoline component streams can be rearranged to improve their properties as gasoline blending components. Reforming is normally carried out in the presence of hydrogen and a catalyst at temperatures of up to 1000 o F. The refinery has five of these units, which perform specific operations as follows: Butamer Unit (13,000 BPD) where normal butane is converted to isobutene. Two Alkylation Units (8,000 BPD and 10,000 BPD) where iso-butane from other units is combined with butylene/normal butane mixture to make alkylate, a high octane, zero sulphur, low vapour pressure gasoline blending component; and Rheniformer No. 1 (9,000 BPD) and Rheniformer No. 2 (28,000 BPD) where gasoline blending stocks are reformed to yield a higher-octane fuel. Product Treating Most refinery streams are treated to remove contaminants such as sulphur, organic acids, metals and surfactants that might be detrimental to engines or the environment. The refinery has five units that are used to treat product streams to remove contaminants: Naphtha Hydrotreating Unit (NHT) (44,000 BPD) where sulphur is completely removed from the naphtha by reaction with hydrogen over a catalyst; Hydrocracker (45,000 BPD) where heavy diesel and light cycle oil are desulphurized in the presence of hydrogen and a catalyst resulting in the production of ultra-low sulphur diesel products; Hydrodesulphurizer (HDS) (56,000 BPD) where the sulphur in diesel blending components is converted to hydrogen sulphide by reacting with hydrogen over a catalyst; Merox Plants (44,500 BPD) where mercaptans, which are odorous compounds, are removed from gasoline and jet fuels; and CD-Tech Unit (58,000 BPD) where sulphur compounds are removed from cat-cracker gasoline in a two-stage process. Steam Production Many of the process units contain heat exchangers to recapture waste heat from process streams. Steam, produced in the refinery boilers and heat recovery steam generators (HRSGs), is used to provide power in turbines and ejectors, to heat processes and materials, and as part of the refining process. 6

7 The refinery currently has four boilers (1, 3, 5 and 6), which burn refinery fuel gas and two HRSGs. The HRSGs operated as stand-alone units until late 2004 when combustion turbines were commissioned as part of the Grandview Cogeneration Project. The combustion turbines generate up to 90 Megawatts (MW) of electricity that is sold to NB Power, a portion (approximately 65 MW) of which is re-sold to Irving Oil Refining G.P. for use in the refinery. The HRSGs now derive a significant portion of their heat input from waste heat generated by the combustion turbines, significantly increasing the efficiency of steam generation. Hydrogen Production Hydrogen, required as a feedstock for the hydrocracker and the diesel and naphtha hydrotreaters, is produced by a Hydrogen Plant where natural gas, low octane gasoline or butane, at high temperature and pressure and in the presence of a catalyst, is converted to hydrogen and carbon dioxide. Hydrogen is also produced as a by-product of the molecular rearrangement process. Storage, Blending and Shipping Approximately 15 to 20 different component streams are produced by the refinery. These products are stored in the tank field before being blended together in appropriate proportions to make various grades of gasoline, low sulphur diesel, jet fuel, furnace oil and asphalt. The finished products are also stored in the refinery tank field prior to being shipped to customers via road, rail, and ship. The tank storage area contains 135 tanks storing crude oil, blending components and finished products. There are also a total of 8 spheres and 10 bullets for storing butane and propane. AIR POLLUTION CONTROL Owing to the complexity of the refinery, air pollution control is achieved through a variety of techniques including engineering design, task and unit specific control technologies, operating strategies and procedures, and programs having specific emission reduction goals. These are summarized in the following sub-sections. Fuel Combustion Controls Generally speaking; there is no air pollution control equipment on fuel combustion stacks (although there are some exceptions). Control is typically exercised by maximizing heat recovery at the process design stage through the choice of fuel and fuel sulphur levels and through optimizing furnace operating conditions. For example, process heaters for Crude Unit No. 4 were designed to be more than 90 percent efficient in terms of energy usage, which is reported to be 20 percent more energy efficient than the furnaces associated with Crude Unit No.1, which they replaced. Sulphur Recovery Refinery processing operations, where possible, are designed as closed cycle operations. This means that there are few emissions to the atmosphere. There are several reasons for this including safety, environmental protection, product recovery, and economics. The lightest fractions produced by each processing unit are stripped of their saleable components and the remaining gases, called 7

8 sour gas (because of the hydrogen sulphide it contains) are sent to the Amine Sulphur Recovery Unit where the hydrogen sulphide is removed. The cleaned gas, known as refinery fuel gas or sweet gas, is used throughout the refinery to provide product heating with minimal emissions. Recovered hydrogen sulphide gas is fed to the Sulphur Recovery Units where the sulphur is recovered for sale to the fertilizer and pulp and paper industries. Some hydrogen sulphide gas is fed to the Sulphuric Acid Regeneration Unit where it is converted to sulphuric acid and used in the alkylation process. Approximately ninety nine percent of the sulphur is recovered in this process with the rest being emitted through the Sulphur Recovery Unit stacks as sulphur dioxide. Water is used in a variety of processes within the refinery to clean and cool product streams. Water that comes into direct contact with petroleum products becomes contaminated and is likewise handled in a closed system. The sour water that results from these operations is cleaned of its impurities in the Sour Water Stripper where hydrogen sulphide and ammonia are removed. The recovered impurities are fed, along with the hydrogen sulphide from the Amine Recovery Unit, to the Sulphur Recovery Units. The refinery presently has: two Amine Sulphur Recovery Units (9,000 BPD recycle rate) and two Sour Water Stripping Units (7,600 BPD). The second units in each case were added during the upgrade to provide additional sulphur extraction capability as well as redundancy for maintenance and other shutdown periods; a Tail Gas Unit to remove additional sulphur from the Sulphur Recovery Units exhaust (tail) gas. The original unit (Sulphuric Acid Tail Gas Unit) installed during the upgrade did not operate as expected so the refinery was required to propose a solution. In 2008, a new unit was installed (the Hydrogenation Amine Tail Gas Unit or HATGU) which is achieving the desired sulphur recovery; a Sulphuric Acid Regeneration Unit to regenerate spent sulphuric acid catalyst from the Alkylation Plants; and two Sulphur Recovery Units (100 long tons per day each). Flares Process units are linked together in a system that allows for pressure relief of vessels being shut down for maintenance or due to upset conditions, such as occurs following a power interruption. The pressure is relieved by piping the excess product to one of three flares where the hydrocarbons are combusted at a safe distance from people and equipment. The flares are equipped with smokeless technology and steam assisted air dispersion equipment. The flare system tips were upgraded in 2004 to reduce noise when additional steam is directed to the flares. In addition, the No. 1 flare was upgraded during the fall 2007 turnaround and as a result of the newer technology employed, noise levels have been reduced. 8

9 FCCU Particulate Control Particulate matter emissions from the FCCU are minimized by a series of cyclonic separators. Flue gases from the catalyst regenerator are passed through six sets of primary and secondary cyclones where centrifugal forces cause the particulate matter to move to the outside surface of the cyclones where they drop to the bottom and are removed. Flue gases from the secondary cyclones are sent to a third stage containing 80 high efficiency cyclones and then to a fourth stage high-efficiency cyclone where the majority of the remaining particulate is removed prior to its being released through the stack. The third stage cyclone was replaced in December, 2007, and the fourth stage separator was replaced in 2009 for more reliable operation and particulate capture. As the flue gas continues through each stage, the size and amount of the particles left in the stream decreases. Recovered catalyst is returned to the unit for re-use or recycled. To further reduce particulate emissions, catalyst fines are no longer added to the unit. FCCU Carbon Monoxide Control As part of the 1976 refinery expansion, a platinum combustion promoter was added to the regenerator. The promoter keeps the heat in the bottom of the regenerator where combustion of carbon monoxide to carbon dioxide is completed without hazard and reduces the concentration of the carbon monoxide emissions from approximately 10 to 0.01 percent. Particulate Matter and Sulphur Dioxide Control on RFCCU A Flue Gas Scrubber (FGS) was installed as part of the Refinery Upgrade Project to control emissions of particulate matter and sulphur dioxide from the RFCCU catalyst regeneration process. Noise Control Noise emissions from the refinery are controlled through the equipment selection process; a silencer to reduce noise on the FCCU was installed in 1995 in response to concerns from neighbours around the refinery. Noise mitigation is recognized as an integral part of the design process and noise level specifications were included in the upgrade project procurement process. In the fall of 2007 the refinery conducted a noise study as a requirement through their Approval to Operate. Although the results of the study showed noise to be within benchmark levels at their property line, it did help identify certain activities and units that contribute to slightly increased levels. As a result, several process and mechanical changes were made (such as the installation of silencers) to reduce intermittent noise levels. Hydrogen Plant Carbon Dioxide Control Primary sources of carbon dioxide within the refinery are from fuel combustion and from synthetic hydrogen production through steam/naphtha reforming. In order to reduce the refinery's emissions of carbon dioxide, recycle a contaminant emission and produce a saleable product, Irving Oil Refining G.P. entered into a joint venture with Praxair Canada Inc., and constructed a carbon dioxide liquefaction plant in the Grandview Industrial Park in Over half of the carbon dioxide emissions generated from the hydrogen plant are now being recovered and recycled as a food grade product. 9

10 Instrumentation and Stack Monitoring The refinery re-instrumentation, carried out between 1991 and 1993, allowed for more frequent and precise control of all refinery processes. This improved control allows the optimization of refinery processes, which contributes markedly to energy efficiency and emission reductions. During reinstrumentation, a second fiber optic communication backbone was installed which provides a backup for the control system and allows the refinery to continue safe operation in the event that a portion of the control system becomes inoperable. Stack emissions are monitored for a number of parameters. In some cases the monitors provide direct measurements of contaminant concentrations such as the sulphur dioxide continuous emission monitors on the sulphur plant stacks. In other cases, such as the furnaces, boilers and the FCCU, process parameters including fuel flow, oxygen, and temperature are continuously measured. These measurements allow for optimal control of the process as well as, in combination with frequent fuel sulphur analysis, for the calculation of sulphur dioxide emissions. Continuous Emission Monitors (CEMs) for sulphur dioxide and nitrogen oxides are operational on the Flue Gas Scrubber, the Tail Gas Unit and the Sulphuric Acid Regeneration Unit. During the construction of the Grandview Cogeneration Project, CEMs for sulphur dioxide and nitrogen oxides were installed on both HRSG's. Operational Procedures The refinery burns refinery fuel gas (sweet gas) to provide heat for the refining process. The 26 stacks emit flue gases from the combustion of refinery fuel gas, natural gas, propane or LPG. Adherence to the Sulphur Dioxide Response Plan also contributes to reducing emissions and minimizing their impact. The operating approval requires the refinery to implement the plan, when ambient sulphur dioxide concentrations are above 8 parts per hundred million (pphm), which is approximately one half the maximum permissible 1-hour ground level concentrations of sulphur dioxide, at any one of five ambient monitors. In order to conserve energy, process heaters and boilers are operated near stoichiometric (ideal) conditions, that is, the minimum amount of air required is used to enable complete combustion of the fuels. This operating objective has the benefit of minimizing emissions of all contaminants. Shutdown, start-up and maintenance procedures are designed to minimize emissions. During planned shutdowns, units are steamed out and the resulting hydrocarbon mixture is burned in the flare(s) with clean fuels, such as propane or LPG, to minimize the hydrocarbon emissions. Wherever possible mechanical procedures are now employed to remove coke build-up on boiler tubes as opposed to the previous practice of slowly burning the coke out. Further, during maintenance of the sulphur plants or associated units, the refinery uses low sulphur crude to reduce the load on the operating sulphur recovery plant. 10

11 Product Quality Product (fuel) quality affects emissions at the refinery level, during product distribution and in product usage. Changes to fuel quality are frequently driven by environmental and health concerns and often become requirements of national fuel regulations in Canada and the United States. The Alkylation Unit (to reduce volatile organic compound (VOC) emissions), and Dehexanizer (for US reformulated gasoline) are process units that were installed between 1987 and 1994 as a result of new Canadian and US federal gasoline regulations aimed at reducing emissions from both gasoline storage and use. More recent federal environmental initiatives necessitated the upgrade to the Diesel Hydrodesulphurizer and the Hydrocracker in 1995, which allowed production of low sulphur diesel. This became a requirement in 1998 as a result of the Diesel Fuel Regulations (3). The Aromatics Saturation Unit was constructed in to reduce the benzene content in gasoline as required by the Benzene in Gasoline Regulations (4). The CD-Tech Unit installed in 2003 as part of the RFCCU provides enhanced capability to ensure that the Sulphur in Gasoline Regulations (5) are met. Irving Oil has also made infrastructure improvements such as new pipelines in preparation for adherence with the ultra-low sulphur diesel requirements mandated under the Sulphur in Diesel Fuel Regulations (6). In 2006, the hydrocracker was converted into a diesel treater to help meet these requirements. In 2010, the refinery started construction of a new Dehexanizer unit to further reduce the benzene content in gasoline to meet US EPA regulations set to come into force in January The unit was commissioned in Fugitive Emissions Programs In 1993, the Irving Oil Refinery began an annual program aimed at reducing its contribution to ground-level ozone in keeping with the Code of Practice for the Measurement and Control of Fugitive VOC Emissions from Equipment Leaks, October, 1993 (7) established by the Canadian Council of Ministers of the Environment (CCME). This program is comprised of the detection and repair of leaks (fugitive emissions) from specific process components such as pump seals, valves, flanges, vents, connectors, and compressor seals. The detection component of the program began in The program was expanded to include the repair of leaking components in Where a repair cannot be made immediately, it is scheduled for the next available maintenance turnaround. In addition, all Irving Oil Refining G.P. storage tanks are required to be maintained in accordance with the CCME Environmental Guidelines for Controlling Emissions of Volatile Organic Compounds from Aboveground Storage Tanks June 1995 (8), and the requirements of this guideline have been incorporated into an annual tank reliability program carried out by the refinery. Since 1995 major improvements have been carried out on the wastewater treatment plant, which have resulted in reductions of odorous emissions. These include the segregation and redirection of odorous caustic streams for off-site treatment, the reconditioning of the Sour Water Tank, the treatment of the equalization pond, and the dredging and disposal of sludge from the bottom of the effluent treatment ponds. In addition, following recommendations in the Odour Impact Study report, further odour reduction techniques have been implemented (see section Compliance with the Approval to Operate for more details). 11

12 POTENTIAL AIR QUALITY CONTAMINANTS The refinery is situated in east Saint John and although it is in an industrial area, there are several residential areas within close proximity. Emissions from the refinery come from four main source areas: Sulphur Block (includes two Sulphur Recovery Units, the Tail Gas Unit and the Sulphuric Acid Regeneration Unit) where, although 99 percent of the sulphur fed to the units is recovered, less than 1 percent is released to the atmosphere as sulphur dioxide as well as small amounts of nitrogen oxides, particulate matter and carbon dioxide. Refinery Boilers and the No. 3 Crude Unit fired heaters where fuel oil and gas combustion results in the emission of sulphur dioxide, particulate matter, nitrogen oxides, carbon dioxide, and small amounts of carbon monoxide and hydrocarbons. FCCU catalyst regenerator where sulphur dioxide, particulate matter, nitrogen oxides, carbon dioxide and small amounts of carbon monoxide and hydrocarbons are emitted. FGS where nitrogen oxides, particulate matter, carbon dioxide and small amounts of sulphur dioxide and carbon monoxide are emitted. Fugitive emissions can also have an effect on local air quality. POTENTIAL IMPACTS OF AIR EMISSIONS Acid Deposition Emissions of sulphur dioxide and nitrogen oxides can be transformed in the atmosphere to acidic particles which ultimately fallout as acid deposition (acid rain is one way in which this deposition occurs). This deposition can occur far from the original source of the emissions. The majority of the acid deposition measured in New Brunswick is caused by emission sources in the US mid-west and central Canada. Generally speaking, acid deposition in New Brunswick has shown gradual improvement since 1990 through national and international efforts to reduce acid causing emissions, primarily through controlling emissions of sulphur dioxide. While some ecosystems have begun to show recovery from the effects of acid deposition, the rate of progress is relatively slow and further reductions will be required in order to afford protection to the more sensitive receiving environments in New Brunswick, e.g. water bodies in the south-western region of the province. Climate Change When fossil fuels are burned it results in the generation of greenhouse gases (GHG) such as carbon dioxide (CO 2 ) and methane (CH 4 ), which are the main contributors to the problem of climate change. Climate change (also referred to as "global warming" or the "greenhouse effect") occurs as a result of industrial and natural pollutants trapping solar radiation and heat in the earth's atmosphere, resulting in a gradual warming of the planet's atmosphere. While natural variations in global atmospheric temperatures have occurred in past centuries, it appears that the rate at which these temperatures are increasing (currently approximately 0.1 C per decade) may be higher than has historically been the case, which may be partly due to a gradual increase in pollutant levels in the 12

13 atmosphere. Left unabated, climate change has the potential to cause serious ecological damage and significantly modify the Earth's climates. Ground-Level Ozone Ozone (O 3 ) is a reactive, unstable form of oxygen. It is not emitted directly from stacks or exhaust pipes, but it is formed as a result of photochemical reactions between other pollutants, most importantly nitrogen oxides and volatile organic compounds (VOCs) such as solvent and gasoline vapours. Both stationary and mobile emissions sources contribute precursor pollutants that have the potential to result in the formation of ground-level ozone. It has been estimated that 85 percent of ground-level ozone enters this region from the North Eastern United States, Central Canada and the American Mid-West (9). Elevated levels generally occur in the summer under very warm conditions when large stable air masses move up the eastern seaboard into the Fundy region. Although the contribution of local sources may pose an added stress to already deteriorating air quality conditions during such episodes, in general local sources are relatively minor contributors to ground-level ozone levels experienced in our region. Control programs in New Brunswick specifically for ground-level ozone are therefore not able to reduce ambient concentrations appreciably. Despite this, all measures which can reduce the emission of ozone precursors are promoted such as the refinery's Fugitive Emissions Program. Of particular interest are programs where multiple environmental benefits may be expected. For example, improving energy efficiency will reduce greenhouse gas emissions as well as nitrogen oxides and sulphur dioxide. Therefore efficiency measures are favoured over measures exclusively targeting ground-level ozone. AIR QUALITY COMPLIANCE AND ENFORCEMENT Compliance and Enforcement options used by the Department of Environment are outlined in the Department's Compliance and Enforcement Policy (10). These may include but are not limited to: schedules of compliance, warnings, orders, and prosecutions. Although not specifically outlined in the Policy, it is also possible to amend approvals with more stringent conditions, both during its valid period or at the time of renewal, to address specific compliance issues or to improve the environmental impact of the facility. Most recently, a new Regulation under the Clean Air Act allows for the issuance of "administrative penalties" for minor violations as an alternative to traditionallyused enforcement options. All sources of air emissions in the province are required to comply with the Clean Air Act and Air Quality Regulation. In addition to establishing ambient standards for contaminants in air, Section 3 of the Air Quality Regulation requires that "no person shall construct, modify or operate... a source without applying for and obtaining an approval... The refinery currently operates under Approval to Operate I-6672, issued March 31, The current Approval expires on March 30, Compliance with the Approval to Operate Following are the key issues addressed in the Approval to Operate for Irving Oil Refining G.P. 13

14 including comments on compliance with the associated conditions and actions taken to achieve compliance with these conditions. A summary of the key conditions are in italics. Emergency Response and Reporting Notify the Department immediately (or the Coast Guard if not during business hours) following an environmental emergency and provide a written report within five business days of the incident. The refinery continues to notify the Department of all environmental emergency incidents following the emergency response conditions in the approval. Environmental incidents of a non-emergency status are reported to the Department via fax. Irving Oil received one warning letter regarding emergency response and reporting. On May 16, 2012 a trip in Plant 143 produced elevated sulphur dioxide concentrations which exceeded the ambient air quality limits at the Forest Hills station. The environmental emergency reporting procedure was not followed as per the Approval. This was addressed and there have been no reoccurrences. Provide the Department with training on the IOL Environmental Emergency Response Plan. This training was conducted on May 25 th, 2011 at the refinery and several members of both the central office and Saint John Regional Office of the Department participated. Total Reduced Sulphur (TRS) Reduced sulphur compounds are highly malodorous. In an effort to better understand the odours associated with the refinery, a TRS monitor was installed by the Department on a temporary basis at the Champlain Heights School in Due to concerns about odours from the refinery affecting neighbours, Irving (through amendment No. 5 to their current approval) was required to install a replacement permanent TRS monitor at the Champlain Heights School monitoring station and also one at the Forest Hills and Midwood Avenue ambient monitoring stations. Historically, the TRS measurements at Champlain Heights were compared to ambient standards for hydrogen sulphide, a component of TRS, because there are no ambient standards in New Brunswick for TRS. Therefore, when the Approval was amended in July, 2007 to require additional monitoring, TRS ambient limits were also included based on new standards being proposed in Ontario (11). Three permanent ambient monitoring stations collect TRS data; Champlain Heights, Midwood Avenue and Forest Hills. Limit ambient total reduced sulphur concentrations to 13 μg/m 3 average and 7 μg/m 3 (5 ppb) as a 24 hour average. (9 ppb) as a 10 minute Generally there are very few issues with TRS at the monitoring stations, although there were a few exceedances during the lifetime of the Approval. 14

15 Table 1: Exceedances of 10 minute average for TRS, East Saint John Midwood Avenue Champlain Heights Forest Hills In 2012 an issue with the seals of Tank 103 caused the TRS exceedances in November and December of The Tank was taken out of service for repairs. Install a replacement ambient TRS monitor at the Champlain Heights ambient monitoring station by September 30, The replacement TRS monitor was installed in 2010, as required. The Refinery shall ensure that the sour-gas-to-sweet-gas by-pass valve remains closed and secured. The valve is not capable of opening. It is locked with a numbered tag. Operate and maintain the TRS monitor at the Midwood Avenue monitoring station and provide the refinery and the Department with real-time access to the information gathered by this monitor. Operate and maintain the appropriate hardware to provide the Facility with access to the data at the two Department ambient TRS monitors. The refinery remains in compliance. Sulphur Dioxide (SO 2 ) Limit annual emissions of sulphur dioxide to 5,400 tonnes per calendar year and 30 day rolling average emissions to 17.5 tonnes per day. The refinery consistently has been below these limits during the period of the approval (see Table 2 for a summary of annual emissions). Over the past five years, average annual emissions of sulphur dioxide have remained well below the limit with the operation of the HATGU system. 15

16 Table 2. Annual SO 2 Emissions SO Average Flue Gas Scrubber FCCU Sulphur Block Boilers, HRSGs, and Process Heaters Flares Total SO 2 Emissions (tonnes/year) Prior to 2000 the Irving Oil refinery had an annual sulphur dioxide emissions cap of 9,500 tonnes. In the EIA for the Refinery Upgrade Project, Irving Oil Refining G.P. proposed a reduction in the annual sulphur dioxide cap to 8,000 tonnes. This cap was included in their Approval to Operate issued in October 2000, and the cap was reduced again to 7,200 tonnes when the Approval was renewed in The emissions cap was reduced again in 2010, to 5400 tonnes of sulphur dioxide per year. Sulphur dioxide emissions from the refinery have typically been stable and consistent as shown in Figure emissions are higher due to the commissioning operations of the new tail gas unit emissions were lower due to a 6 week turn around period unplanned outages that affected higher SO 2 emitting units. Initially following the upgrade overall facility emissions of Sulphur Dioxide (SO 2 ) decreased to levels below those predicted in the EIA Registration; however, in December 2002, there was a failure in the Sulphuric Acid Tail Gas Unit (SATGU) due to overheating. This resulted in emissions returning to pre-upgrade levels. Through 2003, 2004 and 2005, Irving worked to bring SO 2 emissions to levels expected under the refinery upgrade project. Despite achieving facility-wide SO 2 emission reductions that are in line with overall projections, emissions from the Sulphur Block were not reduced by the projected 70%. For this reason and continued exceedances of the ambient objective at the Grandview West 1 monitoring site, Irving was required in May 2005 to propose a solution. The proposed solution was the construction and commissioning of a Hydrogenation Amine Tail Gas Unit (HATGU). Irving Oil registered and received a Determination under the EIA Regulation to install the HATGU. This unit is designed to reduce emissions from the Sulphur Block to less than 3,000 kilograms per day. This represents a 70% reduction from the approved emission limits for the Sulphur Block at that time. 16

17 The new tail gas unit (HATGU) has been in operation since June, Annual SO 2 emissions are shown in Figure 2 below. Figure 2: Annual Sulphur Dioxide Emissions Operate and maintain four sulphur dioxide ambient monitors in the east Saint John area and provide the refinery and the Department with real-time access to the information gathered by these monitors. Operate and maintain the appropriate hardware to provide the Facility with access to the data at the two Department ambient SO2 monitors. As a condition of the air quality approval to operate, Irving Oil Refining G.P. is required to operate and maintain four ambient sulphur dioxide monitoring stations in east Saint John. These are located north of the refinery at the Silver Falls Irving, to the south-south east at the Irving Forest Products site in the Grandview Industrial Park, to the south at the blower building for the Irving Paper lagoon (known as Grandview West 1) and on Midwood Avenue. The Department also operates sulphur dioxide monitors in Forest Hills and Champlain Heights subdivisions. Until February 2003, Irving Oil operated a sulphur dioxide monitoring station at the Three Mile Irving at the corner of McAllister Drive and Rothesay Avenue. However, this monitor had historically recorded low levels and was not providing any benefit in terms of episode control. The Department and the refinery both have rapid access to the information collected at the six monitoring stations. SO 2 emissions from the refinery must be limited such that the maximum ground level concentrations listed in Schedule B and C of the AQR are not exceeded. The refinery is one of several significant sources of sulphur dioxide in the Saint John region and elevated ambient concentrations of sulphur dioxide may result from emissions from any or all of these sources. Therefore while there have been exceedances of ambient air quality standards in east Saint John in the past, the causes of the exceedances could not necessarily be attributed to one source. An exception exists with the measurements taken at the Grandview West 1 site where, exceedances have almost exclusively been associated with winds from a northerly direction. This 17

18 strongly suggests that emissions from Irving Oil are associated with the exceedances. Examinations of the data conducted by both the Department and Irving Oil have determined that the likely sources within the refinery are the stacks associated with the Sulphur Block process units. The exceedances at the Grandview West 1 monitoring station have decreased substantially over the past five years. The exceedances of the sulphur dioxide ambient objectives at various monitoring locations in East Saint John are shown in Table 3. Exceedances have decreased dramatically since the installation of the HATGU and there have been only a few exceedances throughout the lifetime of the Approval. Table 3: Exceedances of Maximum Permissible Ground Level Concentrations (Provincial Objectives) for SO 2, East Saint John Midwood Avenue Champlain Heights Grandview West 1 18 Forest Hills Forest Products Silver Falls 1-HR OBJECTIVE HR OBJECTIVE Implement the Sulphur Dioxide Response Plan as required. The refinery continues to implement the Sulphur Dioxide Response Plan when necessary. Sulphur dioxide concentrations are monitored 24 hours a day by operators within the Refinery Control Centre. If sulphur dioxide levels rise beyond pre-set limits at any one of the six monitors, the refinery takes action to reduce sulphur dioxide emissions in an effort to prevent exceedances of the regulated standards. The information received at the refinery consists of instantaneous sulphur dioxide concentrations, 5 minute rolling averages, and hourly and 24 hour sulphur dioxide averages. Limit total daily sulphur dioxide emissions from the Sulphur Block to 4,000 kgs/day on an annual average. The refinery has been in compliance with these limits throughout the lifetime of the Approval. Continuously monitor emissions of SO 2 from the SRUs, FGS, SARU, TGU and HRSGs. CEMs are installed and operated as required.

19 Nitrogen Oxides (NOx) Nitrogen oxide emission estimates show a decreasing trend from 2009 to 2010 and have remained fairly steady since then. (see Table 4 for details). In 2010 the accuracy in the methods used to determine the numbers was improved. The USEPA emission factors were updated to reflect 2008 data and CEM data was used for various stacks that previously used emission factors. In 2012 a new platforming catalyst in the FCCU that aide in the reduction of NOx emissions was used. Nitrogen oxide emissions reported by the refinery are based on a variety of sources including stack tests, mass and energy balances, U.S. EPA emission factors and design data. The refinery has NOx CEMs on the FGS, TGU, SARU and HRSGs. Over the past five years emissions have averaged approximately 3,141 tonnes per year. Table 4. Annual NOx Emissions NOx Average Flue Gas Scrubber FCCU Sulphur Block Boilers, HRSGs, and Process Heaters Flares Total NOx Emissions (tonnes/year) Develop a Plan to reduce emissions of Nitrogen Oxides (NOx). A Nitrogen Oxides Reduction Report was submitted to the Department in Irving Oil updated the estimations of NO x emissions from the Facility and identified work that had been done to reduce NO x emissions over the last five years. Irving has committed to better quantifying NO x emissions and comparing the emissions to the NFPRER benchmarks for consideration for further study. Operate and maintain one ambient NOx monitor in the east Saint John area and provide the refinery and the Department with real-time access to the information gathered by this monitors. In east Saint John there are currently three monitors that measure concentrations of nitric oxide and nitrogen dioxide. One has been operated at the Forest Hills National Air Pollution Surveillance Network (NAPS) site for at least twenty years. Two more have been added as a result of EIA Regulation reviews on new projects. The Champlain Heights School monitor was installed as a requirement of the EIA Determination on the Bayside Power Project and the Mill Pond monitor (same general location as the Grandview West 1 site but housed in a building at ground level) was installed as a requirement of the EIA Determination on the Grandview Cogeneration Project. These sites became operational in 2002 and 2004 respectively. Continuously monitor emissions of NOx from the FGS, SARU, TGU and HRSGs. CEMs are installed and operated as required. 19

20 Particulate Matter (PM) Particulate matter emissions from the refinery are measured in two ways: material balances on the catalyst being used in the FCCU, and periodic stack tests. Fuel combustion, the FCCU catalyst regenerator stack and the FGS are the major sources of particulate matter emissions from the refinery. Efforts to reduce emissions from the FCCU, improvements in energy efficiency and the use of lower sulphur fuels have contributed to reductions in particulate matter emissions since The estimated particulate emissions over the last five years are 361 tonnes per year, as outlined in Table 5. In 2011 additional source testing on the Fluid Catalytic Cracking Unit (FCCU) was completed to assess the accuracy of particulate emission calculations on this unit. After the review it was determined that the National Framework Petroleum Emissions Reduction recommended method demonstrated fairly consistent results compared to the source testing, although it is still an estimated value due to the high level of error and variabilities. Table 5. Annual PM Emissions PM Average Flue Gas Scrubber FCCU Sulphur Block Boilers, HRSGs, and Process Heaters Flares Total PM Emissions (tonnes/year) Total Suspended Particulate (TSP) Matter was measured at the Forest Hills site until The TSP which measures total particulate, as captured on a filter every sixth day, was replaced with continuous monitoring beginning in Research into the health effects of particulate has lead jurisdictions to focus on finer particulate fractions of PM 10 (inhalable particulate defined as particulate having an average diameter of less than 10 microns) and PM 2.5 (respirable particulate which has an average diameter of less than 2.5 microns and which can enter deeply into the lungs). The continuous monitors operated at the Forest Hills site are of the TEOM design (Tapered Element Oscillating Microbalance). These units are capable of measuring particulate on a real time basis and therefore provide a much more comprehensive history of the particulate concentrations in the ambient environment. As a result of the Refinery Upgrade Project, Irving Oil Refining G.P. was initially required to install two TSP monitors. Given that the particulate matter that was projected to be released from the upgraded facility was fine i.e. PM 2.5, the requirement was adjusted to require Irving Oil to install one PM 2.5 monitor. This monitor was installed at the Champlain Heights School monitoring site in The technology used in this monitor is called BAM for Beta Attenuated Monitor which uses a filter tape to continuously capture particulate. This technology was at the time gaining wider use in the U.S. Since then additional BAM 2.5 monitors have been installed both in the U.S. and Canada. In 2004 a BAM 2.5 monitor was also placed at the Forest Hills monitoring site. 20

21 Operate and maintain one ambient PM 2.5 monitor at the Champlain Heights monitoring station and provide the refinery and the Department with real-time access to the information gathered by this monitor. The monitor is installed and operated as required. Maintain particulate matter emissions from the existing cat cracker within a 12-month rolling average limit of 300 kilograms per day during normal operation. Particulate emissions in the FCCU remain fairly consistent during normal operations, but there have been a few upset conditions during the lifetime of the Approval. Most notably in August of 2010 during a five day period where approximately 28.5 tonnes of catalyst was emitted and particulate was deposited on neighbourhood houses, vehicles and lawns. In June, 2013 an upset emitted 6 to 10 Tonnes of catalyst. In 2011 there were higher than normal particulate matter emissions from the FCCU compared to the other 4 years. Mechanical issues which included a hole in the west hopper as well as a catalyst release from a pressure build up in the dump line attributed to high particulate in January and again in August there were mechanical issues that increased particulate. Following an audit of the Approval in 2013, Irving updated the Environmental Incident Reporting EMSI to include immediate notifications of any maintenance or shut down of the FCCU to be sent as noteworthy events in the chance an upset condition may occur during shut down or start up. The FCCU is an older piece of equipment and it is necessary to do repairs and replace parts during turnarounds. Operate the Flue Gas Scrubber so that an emission rate of 50 mg/nm3 particulate matter on a dry basis is achieved. Annual performance tests conducted on the Flue Gas Scrubber indicate that particulate emissions are below the target emission rate. Volatile Organic Compounds (VOCs) Concentrations of volatile organic compounds have been measured at Forest Hills since In support of the process to validate the assumptions made in the Public Health Risk Assessment for the Refinery Upgrade Project VOC measurements started at the Champlain Heights School monitoring site in A third site was operated at Point Lepreau from 1992 until early 2009, a rural location upwind of the Saint John area. The routine analysis provides results for over 150 different VOCs. The measured VOC levels are well below standards applied in other jurisdictions. A summary of annual VOC emissions over the past five years is provided in Table 6 below. Fugitive emissions are higher in 2013 due to an unplanned shutdown of the RFCCU, which made the leaking components in this area inaccessible. The fugitive emissions in 2011 were also high as 21

22 compared to the average as a larger number of components requiring repairs were designated Turnaround or Shutdown work and could not be completed during the program year. They were completed the following year, as can be seen in the low emissions in Tank farm emissions continue to see a decline, due in part by the Annual Tank Inspection and Repair Program. The Fuel Distribution emissions saw a significant decrease in emissions following a third party study in 2011 conducted at the Gasoline Loading Rack to determine actual VOC emission rates during the loading process. The study concluded that the actual emissions were much lower than the USEPA emission factors previously used. Stack emissions and flare emissions show a reduction from 2009 to 2010 forward due to the removal of methane and ethane from VOC calculations. Methane and ethane are not considered VOCs under the national Pollutant Release Inventory, therefore not included in the reporting of total VOCs. There has also been an initiative by the refinery to reduce the amount of gas flared since Table 6. Annual VOC Emissions VOCs Average Fugitive Emissions Tank Farm Fuel Distribution Stack Emissions Spills Flares Wastewater Treatment Total VOC Emissions Continue to implement the Fugitive VOC Emissions Measurement and Reductions Program in accordance with the CCME code of practice Environmental Code of Practice for the Measurement and Control of Fugitive Emissions from Equipment Leaks. Irving Oil continues to conduct a leak detection and repair program in accordance with the CCME Code of Practice and provides the Department with annual updates as required. All process units are now subject to the program. In excess of 16,000 components are tested annually and leaks repaired where required. Information provided to the Department under the refinery's Fugitive Emissions Program indicate that an annual reduction of fugitive emissions of VOCs from leaking components have ranged from 26% to 45% from 2009 to The program provides a mechanism to control fugitive emissions on an annual basis. These reductions are not cumulative. Rather they represent the average reductions that have been made annually as a result of implementation of the Leak Detection and Repair Program which is, in effect, a maintenance activity designed to limit fugitive emissions. 22