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Refining dangers can be controlled article
Nitrogen is frequently used to purge the space in crude oil and processed fuel tanks to avoid the ingress of air. The oxygen from air could cause an explosive atmosphere inside the tank resulting in hazardous conditions.
A range of industrial cylinder gases are used for welding and cutting of metals during maintenance and construction operations. Welding equipment such as torches, electrodes and related personal protection equipment (PPE) for safety are also required.
The Continuous Catalyst Regeneration (CCR) unit in a refinery reformer ensures optimum process performance, continuous operation and extended catalyst life. To regenerate a reforming catalyst, the following sequence is generally applied:
Step 1 in the catalyst regeneration process above is regulated by measurement of hydrogen or hydrocarbons in the nitrogen at the reactor outlet. When the hydrogen has been desorbed from the catalyst and purged from the reactor, the hydrogen measured value will fall. A thermal conductivity detector (TCD) is often used for hydrogen measurement in this application and will be calibrated using a certified specialty gases process control mixture, 1% hydrogen in nitrogen as the span gas, which would typically represent 100% full-scale deflection on the instrument.
Step 4 will be regulated by measurement of the moisture concentration in the nitrogen purge gas.
The analytical instrumentation used to measure the composition of process streams in process control applications requires high purity instrumentation gases such as helium for gas chromatography or hydrogen for FID detectors to function. These instruments also require frequent calibration using high precision calibration gas mixtures which are available from our specialty gases product range.
The quality control laboratory is the first and last destination for products arriving at and leaving the refinery. Incoming crude is analysed for sulphur content and the broad hydrocarbon footprint. Refined products such as automotive petrol and diesel are analysed to ensure that they meet the quality standards for octane level, benzene and sulphur content. Accurate assay of the light and heavy fuel fractions can assist with fine tuning of the blending operation to ensure that each storage tank contains precisely the correct grade of fuel required. Instrumentation gases such as Helium 5.0 and calibration gas mixtures are required to operate and validate the analytical instrumentation that operates in the QC lab.
Flammable gases such as methane or propane and toxic gases such as hydrogen sulphide are abundant on refineries and petrochemical processing plants. It is common to mitigate the risks associated with leaks of these gases with the use of fixed or portable gas detection equipment which is permanently sniffing for leaks. Gas detection devices require frequent testing and occasional calibration using high precision specialty gases mixtures which simulate the toxic or flammable gases to be detected.
Emissions to air from a refinery or petrochemical facility are unavoidable. Combustion of fuels to generate steam or burning of methane in steam reformer hydrogen generators produces flue gases which are emitted to the atmosphere through the refinery smoke stacks. Continuous emissions monitoring systems (CEMS) are installed to measure stack gas flows and ensure that the emissions of potentially harmful gases such as oxides of nitrogen, sulphur dioxide or carbon monoxide are managed within approved limits. These CEMS systems require validation with specialty gas calibration mixtures to prove their measurements are accurate and therefore the emissions will not be harmful to the environment or public health.
When entering storage tanks for maintenance or cleaning the operator will be working in a confined space where the free flow of air might not be possible. It is likely that the space contains residual vapour from various hydrocarbons or nitrogen gas from purging activity. In any case, gas detection PPE should be worn to give notice of any gas risks and it is also often the case that breathing apparatus will be worn where pure clean air is provided to the operator through pipes and into a breathing mask. Such breathing air is often supplied from cylinders because the local compressed air supply will most likely contain traces of oil and will therefore not be suitable for human consumption. These cylinders can either be of a small size and would be carried with the operator, or would remain outside the confined space in larger quantities and the breathing air would be piped into the worker.
The Refining NZ crude oil refinery at Marsden Point is located close to Whangarei, north of Auckland on the east coast of New Zealand's North Island. New Zealand produces light-sweet crude which is exported to refineries in Australia. However, the Marsden Point refinery processes a medium-sour blend of crude oil which is imported from sources in Asia. Marsden Point produces the majority of New Zealand's refined oil needs, with the balance being imported from Australia and Asia.
The site at Marsden Point was chosen for the oil refinery. Construction began in 1962 and it was officially opened in May 1964. The location is ideally placed at a deep water port in an area with low earthquake risk and close to the major population centres of the North Island. A 168-kilometre pipeline transports up to 400,000 litres per hour of petrol, diesel and aviation fuel to the Auckland oil terminal.
The deep water port at Marsden Point can receive crude tankers up to 130,000 tonnes capacity. Such a tanker may be unloaded within a day and will deliver sufficient product for the refinery to process over a ten day period. The medium-sour crude processed at Whangarei is imported from locations such as Indonesia and Australia.
The crude oil storage tanks are kept safe with a blanket of nitrogen in their head-space to prevent the ingress of air which could cause an explosive atmosphere. The tanker will also have some kind of inert gas supply to its storage tanks and the use of exhaust gases from the engines or an onboard nitrogen generator are typical. Use of nitrogen from shore is also sometimes possible to augment the onboard systems.
Samples of the crude oil will be taken to the refinery QC laboratory for analysis to determine the broad composition of the crude oil and other parameters that are critical to the refinery, such as the total sulphur content. Specialty gases will be used in the laboratory to run sophisticated analytical instrumentation for this quality assay.
The first stage in the refining operation is distillation of the crude oil. In the primary distillation column the lighter hydrocarbons (naptha) are emitted from the top of the column and are used to produce LPG and petrol. Aviation fuel and diesel are withdrawn from the middle of the column. At the bottom of the column heavier hydrocarbon long residue is recovered for further treatment by vacuum distillation and cracking, where it is converted to form liquid fuels or bitumen.
Before the crude oil enters the distillation column it is heated. Additionally, there is a boiler at the base of the distillation column that vaporises the long residue to send the volatile products up the column. The refinery requires vast amounts of heat energy to operate and it therefore produces high pressure steam. Various hydrocarbons from the refinery are used in a flame combustion chamber to fire the steam boiler.
Combustion process control requires measurement of the oxygen concentration in the flue gas to ensure that the mixture inside the combustion chamber is fuel-lean and air-rich. Such process control instrumentation requires calibration with certified specialty gases mixtures and zero setting with high purity nitrogen.
In addition to oxygen measurement in the flue gas from the combustion chamber, it will be necessary to measure and control NOx emissions levels using continuous emissions monitoring systems, known as CEMS. To mitigate NOx emissions from flame processes, SCR units can be installed. The CEMS will require span gas mixtures of NOx in nitrogen for calibration and also zero gas. The SCR unit will use similar instrumentation for process control.
The diesel, aviation fuel and petrol produced during primary distillation must be treated to remove sulphur before they can be sold for use. This ensures that when they are burned in car, truck or airplane jet engines the emissions do not pollute the atmosphere with sulphur dioxide. The reaction to remove sulphur takes place at high temperature and pressure and results in the production of hydrogen sulphide (H2S).
To ensure that this process is operating correctly and under control, the analysis of total sulphur content of the resultant desulphurised fuels will take place using on-line instrumentation which is most often based on pulsed ultraviolet fluorescence (PUVF) spectrometry. The maximum allowable total sulphur concentration in diesel fuel is 50 ppm.
To determine the total sulphur content all organically-bound sulphur must be converted to sulphur dioxide through an oxidation reaction. A high purity air carrier gas is used to deliver the sample from the injection valve to the air bath oven where the sample is fully vaporised. After vaporisation, additional air is added and this mixture of hydrocarbons and air is fully combusted to CO2, H2O and SO2 in a pyrolyser operating at around 1100°C.
At the measurement cell, the sample is exposed to ultraviolet light which is absorbed by the excited SO2 molecules. As the SO2 molecules enter a relaxed state they re-emit UV light at a different frequency and this change in UV light emission frequency is interpreted by the detector in the instrument. Calibration of the analyser is required at regular intervals using a certified SO2 in nitrogen specialty gases calibration mixture.
Desulphurisation of fuels produces vast quantities of hydrogen sulphide gas. H2S is toxic and flammable, so a release to atmosphere is highly undesirable. All around the desulphurisation equipment there are gas detectors which are permanently sniffing for leaks. In addition to the network of fixed gas detectors, refinery personnel will generally also carry a portable H2S detector as part of their PPE to alert them to the presence of this toxic gas. These detectors are checked regularly with certified specialty gas mixtures to ensure they are functioning and are periodically sent to a service laboratory for thorough calibration and maintenance.
To avoid emissions of H2S to the atmosphere it is converted to elemental sulphur in the sulphur recovery unit. The operating principle is combustion of the H2S with air to form SO2 in a Claus burner. The resultant SO2 then reacts with H2S from the feed stream to produce sulphur and water. A further catalytic process increases the conversion to approximately 96%.
The final step in the sulphur recovery process is to use a Shell Claus Off-Gas Treating (SCOT) unit which results in 99.8% sulphur recovery from the H2S feed gas. The investment in this SCOT unit cost NZ$30 million and was implemented to protect the air quality in New Zealand and minimise H2S and SO2 emissions to atmosphere. The typical emission level from a SCOT process will be less than 50 ppm of SO2. The final emissions from such a process can be assessed and controlled using CEMS for process control and a suite of associated calibration gas mixtures is required to validate the measured results for legislative compliance.
In past decades, New Zealand fuels standards have reduced the level of benzene allowable in transportation fuels. For example in 2004 benzene content was capped at 3% by volume; this was further reduced to 1% in 2006. This 1% level is now generally in line with many other nations such as Australia and the USA. This reduction has been implemented primarily to reduce the carcinogenic potential of petrol emissions from cars and reduce benzene VOC emissions at filling stations and in the fuel storage supply chain.
One of the most recent investments at Refining NZ was known as the Future Fuels Project which cost NZ$180 million across various projects. Part of this project entailed installation of a benzene conversion reactor, which adds hydrogen to benzene under high pressure and in the presence of a catalyst to convert it to cyclohexane.
Gas detection for benzene leaks around the benzene recovery facility is essential. The toxicity and carcinogenic potential of benzene is high and the New Zealand Workplace Exposure Standards and Biological Exposure Indices (9th edition, Nov 2017, amended Jan 2018) declares an 8 hour TWA of only 1 ppm and a STEL of 2.5 ppm. In such applications, typically fixed gas detection systems sniffing for a range of gases known as BTEX (benzene, toluene, ethylbenzene and xylene) will be in place in addition to the use of portable BTEX gas detectors by the refinery staff.
To ensure that these gas sensors are operational - as they must be to perform their safety-critical function - they will be tested regularly with functional test gases to generate an alarm signal. In addition to this so-called bump test, the units will be calibrated at regular service intervals using high precision gas detector calibration gas mixtures.
In Australia and New Zealand, the standard octane level for petrol is 91 RON. Higher RON fuels are also used up to 95 or 98 RON. Naptha from the top of the primary distillation column is not sufficiently high in octane to be sold as a commercial automotive fuel. To increase the octane value the naptha is fed to the platformer. This is a series of reactors that combine the naptha with hydrogen over platinum catalysts to convert the linear hydrocarbons such as hexane to cyclohexane. The result is that the naptha octane value of 50 is increased to 95 to 100 octane in the platformate.
Measurement of the octane value or RON can be achieved using various techniques. In the QC laboratory, it would be common to use an FTIR to generate a characteristic footprint of the petrol mixture. For online measurement, it is increasingly common to use NIR (near infrared) spectroscopy.
The long residue from the primary distillation column undergoes a second phase of distillation under vacuum. This extremely low pressure allows further separation of heavy short residue, which goes for further processing in the bitumen de-asphalting unit and waxy distillate, which is processed in a hydrocracker to break it down to lighter hydrocarbons to produce liquid fuels such as petrol and diesel.
The bottoms products from the vacuum distillation are extremely heavy, sticky hydrocarbons. Some lighter top ends are recovered using a hot stream of butane as a carrier gas. The heaviest bottoms ends are used as bunker fuel oil in shipping or are send for asphalt production in the bitumen unit. The shipping industry has traditionally used bunker fuel due to its low cost.
Bunker fuel is rich in sulphur and maritime emissions have in recent years been a major cause of SO2 emissions to the atmosphere. This is changing with the introduction of new MARPOL Annex 6 regulations and the establishment of several sulphur and NOx emissions control areas (ECAs) globally. To reduce SO2 emissions, it is either required to use low sulphur fuel when steaming in an ECA or to use a scrubber to remove SO2 from the exhaust gases. When steaming in the open ocean, use of low sulphur fuel is not required and, to minimise operating costs, it would therefore not be used.
With this backdrop in mind, in almost all cases over the past decade and since this issue came onto the global agenda with serious impact, the preference has been to use scrubbers instead of the dual fuel option. Quite simply, the cost and complexity of producing and storing a low sulphur grade of bunker fuel in a parallel supply chain on shore and on board ship has driven the economics towards the use of onboard scrubbers. Scrubber performance can be monitored using CEMS systems which are almost identical to those used for stack emissions monitoring on land. These systems require CEMS specialty gas mixtures for calibration and high purity Zero Air or Nitrogen 5.0 grade for zero setting.
The middle fraction of the vacuum distillation is known as waxy distillate. It is too heavy to use as an automotive or aviation fuel but light enough for further processing in the cracker where it is mixed with hydrogen in the presence of a catalyst to break the large waxy hydrocarbons such as heptane or octane into lighter molecules such as butane. The output of the hydrocracker is distilled to separate the lighter components such as LPG and automotive petrol from aviation kerosene and diesel.
The hydrocracker at Marsden Point uses 140 tonnes per day of hydrogen, which is produced on site in a catalytic steam reformer. A by-product of the process is carbon dioxide, produced from the combustion of butane and platformer tops gas. The carbon dioxide is recovered and purified for use in food and beverage applications. Liquid carbon dioxide can be used for freezing and chilling of meat and poultry, while food grade carbon dioxide as a gas is added to soft drinks and beer to form the bubbles or used to package food to maintain freshness over extended periods of time.
The first step of a catalytic steam reformer (CSR) is to react the hydrocarbon feedstock with steam over a catalyst at high temperature to create raw syngas by formation of H2 and CO. In many facilities worldwide the CSR would be natural gas, but at Marsden Point other, higher hydrocarbons more freely available on the refinery are used as feedstock.
The reformer conversion yield and efficiency can be measured with an FID instrument to detect unreacted hydrocarbons. The target products of this first reaction phase CO and hydrogen can be measured with an NDIR instrument and TCD analyser respectively.
During the next step shift converters remove the CO by reaction with steam to form CO2 and H2. The residual CO concentration can be measured again using an NDIR analyser as a process control loop to adjust the efficiency of the shift converters.
The CO2 is then absorbed in an amine absorber and the measurement of CO2 in the scrubber off-gas, which might be at a target value of 3%, would typically again be with an NDIR instrument. This measurement value can influence a process control loop that determines absorber efficiency such as control of the absorber operating parameters such as amine scrubber regeneration and amine re-circulation flow rate.
A final step that is sometimes used in the CSR process can be the inclusion of a methanator to convert traces of CO and CO2 into CH4. These traces of CO and CO2 can be monitored with NDIR analysers. For process control, a TCD can be used for hydrogen for process monitoring and gas purity.
The FID, NDIR and TCD analysers above will all require a certified specialty gases calibration mixture, sometimes referred to as span gas or test gas. For this application the CO and CO2 mixtures could be filled in a balance of nitrogen. The final hydrogen measurement with the TCD analyser is measuring a high concentration of hydrogen and, even though the hydrogen is the measured value, the span gas might be prepared as a mixture of 1, 5 or 10% CO in a balance of hydrogen.
Integral to the Refining NZ operation at Marsden Point is a quality control laboratory called Independent Petroleum Laboratory (IPL) Limited which operates as a subsidiary of The New Zealand Refining Company Limited. This company is New Zealand's specialist petrochemical testing laboratory and provides testing services to the refinery and the wider oil and gas industry in New Zealand and overseas.
IPL delivers accurate, ISO 17025-accredited results. For tests falling under such an accreditation, laboratories such as IPL will need to use ISO 17025 calibration gas mixtures or ISO Guide 34 accredited reference materials because the results they can give are only as good as the calibration that they achieve of their own instruments.
The laboratory is suited to the analysis of liquids such as crude, petrol, diesel, gas, waste oil, fuel oil, biodiesel and ethanol. Downstream analytical services such as biofuels testing, mercury analysis, contamination and purity analysis, environmental testing and chemical testing are also possible. IPL also provides upstream oil and gas industry testing services, such as crude assays.
The instrumentation typically used in such laboratories for hydrocarbon analysis are gas chromatographs fitted with FID or TCD detectors for quantitative work and GS-MS setups for qualitative analysis. The chromatography column will require a carrier gas such as Helium 5.0 grade or Hydrogen 5.0 grade. For the FID detector, Hydrogen 5.0 and zero air instrumentation gases will be required to generate the flame.
The laboratory is also able to conduct industrial waste water and sewage effluent analysis for contamination or consent monitoring. For such purposes, TOC analysers are used which consume Zero Air for TOC oxidation to CO2 which is measured on an NDIR detector.
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