Mercury removal processes
A careful evaluation of the options for removing mercury from natural gas plant feed and product streams is a prudent exercise
NEIL ECKERSLEY and DAVID RADTKE, UOP a Honeywell Company
LEON ROGERS and SHAWN BRENNAN, Enterprise Products
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Mercury is present in many of the world’s natural gas fields. Process plants with brazed aluminium heat exchangers, including LNG facilities and nitrogen rejection units, are particularly susceptible to corrosive attack by mercury. There is an increased awareness on the part of gas processors to better protect their assets and address environmental concerns by removing mercury at the most appropriate location from their facilities.
The use of sulphur-impregnated activated carbon has been prevalent in protecting process plant equipment from mercury ingress via natural gas streams. However, over the last decade, carbon-based options have been replaced in many facilities by the use of more specific base and noble metal- promoted, non-regenerative and regenerative solutions.
A comparison of these more up-to-date mercury removal process solutions is made in three case studies, and the individual plant drivers leading to the requirement to remove mercury are discussed.
Why remove mercury?
Mercury is a naturally occurring element found in small but measurable concentrations in an increasing number of hydrocarbons globally. From refineries to natural gas plants, from coal-fired power stations to petrochemical production facilities, mercury is becoming more prevalent and problematic, and technologies to mitigate against the effects of mercury are in demand more than ever before. Mercury is often associated with natural gas, condensates, C3-C6 refinery product streams (such as naphtha, gasoline and LPG) and petrochemical feed streams. Each of these hydrocarbons is challenged in various ways when mercury is present, and process plants and pipeline assets often require a complete removal of mercury as a result.
Removal and capture of mercury is important for a number of reasons:
• Process plants with brazed aluminium heat exchangers are susceptible to corrosive attack by mercury, and alloys of aluminium are prone to liquid metal embrittlement (LME), causing serious structural damage, particularly when liquid mercury comes into contact with air or water
• Product streams such as condensates, LPG, NGL and naphtha (in the case of refineries) are less valuable when “distressed” by mercury
• Many refinery and petrochemical catalysts are poisoned by mercury. Mercury has the ability to manifest itself in many crude column products and is measurably present in many downstream unit operations. Since increasingly refiners are set up to sell downstream â€¨crude fractions to analogous â€¨petrochemical customers, consideration should be given in removing mercury even from trace levels to gain more value from individual petrochemical feed streams
• Mercury may have health and safety impacts in certain applications.
Types of mercury associated with hydrocarbon streams
Mercury takes on several different chemical forms, depending on the hydrocarbon in question. Figure 1 lists four forms of mercury. These discrete categories exist in natural gas, condensate and crude oil.
Elemental and organic mercury fall into the category of being hydrocarbon soluble. Ionic mercury species are water soluble and comprise examples that include both sulphate and chloride salts of mercury (HgSO4 and HgCl2). Suspended mercury is a broadly defined descriptor comprising particulates including mercury-containing species such as HgS.
Levels of mercury in natural gas
Different areas of the world have varying levels of mercury in their natural gas reservoirs. Figure 2 shows average mercury levels that have been reported to UOP. In recent years, mercury levels have increased from typical highs of 30 or 40 ug/Nm3 to levels exceeding 1000 ug/Nm3 in the Pacific Rim area. With a greater understanding of levels in specific geographical areas â€¨has come a greater level of expectation in terms of what is required to remove mercury both on- and off-shore in a variety of locations worldwide.
Need to protect cryogenic equipment
A well-known reason to remove mercury in a natural gas processing plant is to protect brazed aluminium heat exchangers and the cold box in nitrogen rejection units, to prevent the compromising of these valuable pieces of equipment. In the early 1970s, trace levels of mercury accumulating in the cryogenic recovery section of an LNG production plant at Skikda, Algeria,1 caused catastrophic failure of a heat exchanger. It was found that a combination of mercury and water at temperatures around 0°C caused corrosion in aluminium tubes constructed from aluminium alloy 6061. Subsequent studies revealed far more data on the mechanistic details of how mercury reacts with aluminium, with aluminium diffusing into the mercury droplet followed by conversion to Al2O3 by reaction with air and water.
The consequence is that â€¨mercury bores into aluminium â€¨and significantly compromises aluminium-containing equipment. Specifically, LME has been responsible for a number of failures in the 40 years since the Skikda incident. LME can cause crack initiation and propagation, particularly in the proximity of a weld.2 In order to safeguard against the catastrophic failure of cryogenic equipment, typical maximum levels of mercury are now required in and around these valuable cold boxes within gas processing trains. One level that has found prominence is that the gas entering cryogenic equipment contains no more than 10 ngHg/Nm3 gas.
Importance of measuring mercury
Mercury needs to be measured in order to determine which mercury removal option will provide the most cost-effective solution to meet desired results. Whether it is simply removing the mercury from a process stream to meet specification, protecting the entire plant or ensuring mercury removal for environmental compliance, mercury levels must be known. In order to properly design a mercury removal system, accurate mercury measurement is critical to properly size the system and to avoid having a system that is overly large and uneconomical or too small to satisfy the required outlet mercury â€¨specifications. For existing units, mercury levels in the feed must be monitored for changing inlet levels that might exceed the designed capabilities of the mercury removal unit (MRU). Finally, monitoring the mercury levels exiting the mercury removal unit is critical to verifying proper performance and protection of downstream equipment.
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