LNG is a transportable fuel and an important export from Australia. Processing requires sophisticated gas mixtures to calibrate analysers and hydrocarbon gases as refrigerants.
LNG is a liquefied form of natural gas. It is methane-rich and a relatively clean burning fuel. The purification of LNG from natural gas involves the removal of carbon dioxide (CO2), water, hydrogen sulphide (H2S) and mercury from the natural gas source. Water and H2S are removed to avoid corrosion of the LNG processing and distribution equipment.
CO2 is removed because it would solidify at the extremely low temperatures in the LNG liquefaction process and block all of the pipes and processing equipment; this is another good reason to remove moisture too. CO2 is effectively 'dead weight', both in LNG and vapourised natural gas, because it has no calorific heating value when the gas is burned.
Mercury is removed to avoid condensation of mercury in the liquefaction train, which would damage the high-speed compression equipment as it amalgamates with the aluminium heat exchangers used in the cryogenic liquefaction unit. This amalgam effectively dissolves the aluminium and forms gas leaks. Mercury removal also minimises toxic pollutant emissions when the natural gas is burned.
The process steps involved in LNG purification must be tightly controlled using process control analysers to ensure that the required reduction in water, hydrogen sulphide and CO2 have been achieved. The instrumentation used for this process control will require frequent calibration using specialty gas mixtures.
Methane is the lightest hydrocarbon molecule, so is difficult to liquefy. Cryogenic liquefaction systems must be used to achieve the -162°C temperature required to turn the methane gas to methane liquid. Despite these technological challenges, the benefit of LNG production versus transportation of natural gas as a compressed gas is that the liquid can be shipped over large distances, like crude oil, in ocean-going tankers.
Countries in Asia with relatively few energy resources can thus import LNG and vaporise it for injection into the local natural gas pipeline grid for domestic and industrial consumption. Australia is a net exporter of LNG which is produced from various natural gas fields off the northern coast stretching from Western Australia across to Queensland.
LNG must be stored in insulated containers to avoid spontaneous vapourisation of the LNG. Pearlite, polyurethane foam, polystyrene foam or fibreglass wool are all used as insulation materials. Some amount of heat ingress is inevitable and the resulting boil-off gases are either added to the distribution grid for land based storage or, for on-ship storage, they may be burned in the ship's engine as fuel or re-condensed.
Throughout the LNG processing, storage and distribution operations, the avoidance of gas leaks and their immediate detection is of primary concern. A leak of methane into air will quickly form an explosive gas mixture. Gas detectors are used extensively to ensure the smallest leaks are quickly discovered and repaired. The sensors in these gas detectors are tested frequently to check that the device is functional when it needs to be; this is known as a 'bump test' and uses specialty gases mixtures. For longer term maintenance, it is typical to conduct calibration at annual intervals using more accurate ISO/IEC 17025 or ISO 17034-accredited traceable gas detector calibration gas mixtures.
Natural gas flows from the seabed to a phase separator where solids, water, hydrocarbon liquids (known as condensate) and gases are separated. The phase separator is a mechanical device that allows physical separation. The solids, which are sand from inside the gas well, and the water are removed from the valuable hydrocarbon process stream. Natural gas condensate is similar to the petrol fraction recovered during the distillation of crude oil. In this process it is the 'heavy' end and in crude oil refining, petrol is the 'light' fraction.
The composition of the condensate and gas phases coming off the phase separator are measured accurately to assess the type of gas coming from the well and ensure the process parameters are adjusted accordingly. The CO2, hydrogen sulphide, water and methane content in gas are critical measurements. The propane, butane and higher hydrocarbon composition of the condensate are analysed. The analysis uses a highly accurate gas chromatograph with an FID or TCD detector. Gas chromatography is able to identify and quantify the concentrations of the components in the process streams.
A carrier gas such as Helium 5.0 or Hydrogen 5.0 is chosen for the chromatography. If an FID detector is used, there will be additional requirements for Hydrogen 5.0 grade and Zero Air to create the detector flame. The gas chromatograph is calibrated using a gas mixture containing similar components to the process stream that is to be analysed. The quality level for this gas mixture would generally be a certified gas mixture with low measurement uncertainty, backed up with an ISO/IEC 17025 accreditation. For custody transfer applications, a certified gaseous standard reference material accredited to ISO 17034 is often specified. Such a mixture may also be used for process control, but is not generally specified.
For the carrier and detector gases, two-stage regulators are required because these are continuous flow applications. Chrome-plated brass would be appropriate to cope with the high purity gases. However, in many offshore environments and, especially for sour gas processing where H2S may be present in the air, stainless steel regulators are specified to avoid external corrosion of the chrome-plated brass body.
The calibration gas may be applied with a single-stage regulator because this is a one-time introduction of the gas, not a continuous flow. Since the calibration gas may contain mercaptans or hydrogen sulphide, it will be essential to specify a stainless steel regulator to avoid the risk of reactions between the calibration gas and the regulator itself.
Gases recovered from the condensate separator are processed in the amine gas sweetening unit. In the first stage of this process, the gas scrubber contactor removes hydrogen sulphide and carbon dioxide from the mixed gas stream. The amount of CO2 and H2S in the feed gas depends on how sour the natural gas is. In some cases, the system will be designed to remove more than 10% of the CO2. The second stage strips out the CO2 and H2S from the amine solution to regenerate it. Depending on the process, the H2S will be processed in a sulphur recovery unit such as a Claus burner or the SCOT process. It is essential that sulphur levels in natural gas are low to ensure the product will burn cleanly in houses and for other industrial applications. H2S also reacts with moisture to form corrosive acid which would destroy the gas distribution pipework.
Measurement of hydrogen sulphide in the off-gas from the amine stripper is also a critical process control step to minimise energy consumption. The target H2S level will be less than 5 ppm. The most trusted H2S measurement, to ensure there is no breakthrough of H2S in the natural gas, is the Lead-Acetate Tape analyser that provides an output proportional to the concentration of H2S. The operating principle is that a precisely controlled gas sample flow is humidified and passed over a lead acetate sensing tape, which reacts with the H2S to change colour. An LED light source shines through the tape to a photodiode detector. The received signal is digitised by a microprocessor and related software to result in a linear 4-20 mA output. Calibration of this process control instrument is generally conducted every three months with the introduction of a high precision calibration mixture containing a known concentration of H2S at approximately 60% of the full-scale deflection on the instrument, so a certified calibration gas mixture of 5 ppm H2S in nitrogen would be ideal.
In the broad field of hydrocarbon processing, there are alternative measurement techniques for H2S, such as tunable diode lasers and pulsed UV fluorescence for total sulphur analysis. However, the lead acetate tape method is favoured for operational process control of the amine gas sweetening units.
Dehumidification is the next process step. Moisture removal is essential for several reasons. Firstly, it would form ice in the LNG liquefier and block the pipework. Moisture also reacts with SO2 or H2S, which may be present in the natural gas in small quantities; the resultant acids would attack the pipework and cause leaks. Last, but by no means least, moisture reacts with CO2 and hydrocarbons to form hydrates, which are waxy solids that can block pipes and cause flow restrictions to vital instrumentation and valves.
Similar to the amine gas sweetening unit, the glycol dehydration unit operates with two stages: a gas liquid contactor and a glycol regenerator. The contactor is a scrubber-type unit that removes water from the natural gas stream. The water-laden glycol is then processed in a second unit where the water is boiled off from the glycol in a distillation process.
The target moisture content in the natural gas at the outlet will be around 1 ppm. Continuous, on-line moisture measurement at critical points in the process is essential to ensure successful processing and efficient, reliable plant operation. Measurement will typically be with an impedance moisture sensor, which measures the adsorption of water vapour into a porous non-conducting 'sandwich' between two conductive layers built on top of a base ceramic substrate. The active sensor layer is less than one micron thick and the porous top conductor that allows transmission of water vapour into the sensor is less than 0.1 micron thick. The sensor can respond rapidly to changes in moisture, such as during process start-up or dynamic load conditions. Calibration of the instrument during operation can be achieved by passing wet gas of a known concentration over the sensor. This gas may be generated by a humidity generator or be supplied as a pre-mixed certified calibration gas.
Mercury levels in natural gas can range from less than detectable to approximately 10 ppb by volume. Mercury is removed in the MRU using a molecular sieve to avoid problems in the subsequent cryogenic liquefaction unit. The target mercury concentration is less than 0.01 μg/Nm3 which corresponds to about 1 ppt by volume. Mercury removal is done using molecular sieves.
Mercury at the outlet of the MRU can be measured using cold vapour atomic absorption spectrometry (CVAAS). This differs from other AAS techniques because there is no flame or plasma. The instrument requires high purity instrument grade air as a carrier gas. Another popular technique for online mercury analysis in the petrochemical industry is atomic fluorescence which follows the ASTM 6350-98 and ISO 6978-2 procedures. This technique requires the use of either Argon 5.0 or Nitrogen 5.0 as a carrier gas. Both methods can be calibrated using a mercury generator system.
The final unit operation is cooling of the gas stream to create liquefied natural gas at -162°C. In addition to the production of LNG, other liquids are produced, such as LPG and some heavier C5+ hydrocarbons similar to the petrol fraction resulting from crude oil refining.
The liquefier uses hydrocarbons that are produced within the process as refrigerant gases. During normal operation, any leaks from the refrigeration system can be topped up with hydrocarbons from the process chain. However, for system startup and commissioning it is often required to import the refrigerants. On the Prelude FLNG, high purity ethane and propane are sourced for this start up operation for many refrigeration units. Other LNG refrigeration trains operate with ethylene, which is generally much easier to obtain. However, a risk assessment study during the Prelude FLNG design determined that transportation of ethylene to the floating facility and use at startup would be more risky than the use of ethane and propane, so these refrigerants were selected.
Bespoke sourcing of high purity hydrocarbons for liquefaction train start-up is a highly specialised service in which the specialty gases team at Coregas have much experience and a successful track record.
The end result of the natural gas purification and refrigeration process is liquefied natural gas. The product is stored as a cryogen. At the extremely low storage temperature only stainless steel, aluminium or quenched and tempered 9% nickel steels have the fracture toughness and crack arrest properties required for safe construction of tanks and vessels. For large and land-based storage tanks 9% nickel steel is used because of its high strength. These tanks are at atmospheric pressure and refrigerated to minimise boil off losses.
In maritime operations, it is most common to use an aluminium inner liner with a stainless steel outer shell. Insulating materials are packed between the two layers. The storage tanks are spherical because this is structurally the strongest shape and therefore allows the thinnest materials to be used, saving weight in the vessel and allowing more payload to be transported.
One of the highest risks for LNG shipping is air ingress into the storage tanks. A mixture of LNG and oxygen would produce an explosive atmosphere. Furthermore, moisture from the air would be unwelcome. The tell-tale sign of air ingress would be high oxygen levels, so atmospheric oxygen is effectively used as a leak-detection tracer. The possibility of air ingress is most acute when tanks are being emptied. Oxygen measurement is undertaken prior to refilling the LNG tanks with a new charge or during re-commissioning LNG tanks after maintenance.
The analysis of oxygen is done using highly sensitive on-line analytical equipment such as a paramagnetic oxygen analyser. To ensure accurate measurement, this analyser will be calibrated using either air or a certified calibration gas mixture containing a known concentration of oxygen in nitrogen. The instrument also requires a zero gas such as Nitrogen 5.0. The desirable measured oxygen concentration would be less than 0.1%; any level approaching 2% would be indicative of a serious failure and would trigger an alarm.
Prior to transfer of the LNG from the Prelude FLNG to another ocean going tanker, the natural gas composition must be accurately measured. Billing is based on the methane content in the natural gas and it is also important to check the water and hydrogen sulphide levels are low enough to meet the product transfer quality specification. For this 'custody transfer' analysis an accurate gas chromatograph will be used. It is able to quantify the concentrations of the components in the LNG and to speciate among the different chemicals present.
The gas chromatograph uses high purity Helium 5.0 grade or an equivalent high purity grade of hydrogen as the carrier gas to transport the natural gas through the chromatography column. Essential to the measurement accuracy is that the gas chromatograph is calibrated prior to the analysis using a gas mixture similar in composition to the LNG. The quality level for this gas mixture must be the best available, with low measurement uncertainty backed up with an ISO/IEC 17025 accreditation. Alternatively a certified gaseous standard reference material accredited to ISO 17034 will be specified.
For the instrumentation gases two-stage regulators should be specified for these are continuous flow applications. Chrome-plated brass is suitable as a body material for these high purity gases. On the other hand, in offshore environments and natural gas processing where sea spray and H2S may be present in the air, stainless steel regulators are generally specified to avoid external corrosion of the regulator body.
A single-stage regulator may be used for the calibration gas mixture because this is not a continuous flow application. Since the calibration gas may contain traces of sulphur compounds and low levels of hydrogen sulphide, it will be essential to specify a stainless steel regulator to ensure that the calibration gas purity is retained and to avoid reactions with a brass regulator body.
Coregas has a broad NATA-accreditation scope for the production of synthetic natural gas standards. We are able to produce multi-component ISO 17034-accredited reference materials with hydrocarbons from C1 to C10. All these products are traceable to international standards. In addition to production of high quality calibration gases, we aim to provide a speedy and reliable delivery service. We understand the need for speed in this business and will always be ready to go the extra mile for you.
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