Patrick Sarrazin, Charles J. Cameron, Yves BarthelInstitut Francais du Petrole Rueil Malmaison, France
M. Edward MorrisonIFP Enterprises Texas Inc. Houston
The wide range of mercury and arsenic species sometimes present in raw condensates or crude oils can cause major problems such as corrosion and reduced catalyst life.
However, simple, low-investment, feedstock treatment procedures have been developed that eliminate both As and Hg impurities with very high efficiencies.
BACKGROUND
During the past 20 years, refiners and petrochemical producers have experienced a serious increase in catalyst poisoning caused by mercury and arsenic. This phenomenon may be partially explained by the diversification of the feedstock supply resulting from the need to optimize the profitability of refining and petrochemical operations.
The utilization of a more diverse feedstock supply containing metal impurities has led to operating problems such as corrosion of aluminum alloys in steam cracker cold boxes.12
Moreover, catalytic processes such as selective hydrogenation, working downstream of the steam cracker separation train, suffer from reduced cycle lengths and lifetimes because of poisoning. (Selective hydrogenation as pretreatment for an alkylation unit is especially susceptible to mercury and arsenic poisoning.)
Contamination by mercury and arsenic has been frequently observed on C3, C4, and gasoline hydrogenation catalysts.
In the early 1980s, the integration of light olefins cuts from the fluid catalytic cracker (FCC) with petrochemical operations generated new classes of arsenic poisoning of C3 cut hydrogenation catalysts.
Arsenic and mercury contamination can occur together or separately, depending on the type of raw material used and the process arrangement.
CONDENSATES
The presence of mercury (Hg) in natural gas has been detected in numerous fields for many years. Mercury found in natural gas is generally in metallic form and its concentration varies from 1 to 75 mg/normal cu m.
Natural gas-associated condensates are very different. First, the mercury found in condensates is present in various chemical states: elemental, ionic, and organometallic. Second, arsenic (As) is often simultaneously present. Third, the concentration ranges of mercury and arsenic are generally 10-3,000 ppb and 10-150 ppb, respectively.
The distribution of mercury and arsenic for a Southeast Asian condensate is shown in Figs. 1 and 2. For this particular condensate, the large majority of mercury is found in the naphtha and kerosine fractions, whereas arsenic was found almost exclusively in the residue.
This example should not be considered standard, however, as another Asian condensate was found to have almost all of the arsenic in the naphtha fraction.
It is difficult, without thorough analysis, to determine the mercury and arsenic distributions in raw condensate fractions because of the wide range of boiling points exhibited by the different species that may be present. Tables 1 and 2 list some of the mercury and arsenic compounds that fall within the boiling ranges of some of the condensate fractions.
A comparison of Tables 1 and 2 with Figs. 1 and 2 shows that there is no simple logic based on boiling points that explains the Hg and As distribution; nor is it logical that only elemental Hg is found in the lowest boiling fraction, methane.
CRUDE OIL
Many crude oils, such as those from certain areas in the Southwest U.S., Russia, China, and other areas, contain a wide range of organo-arsenic compounds. This arsenic presence can lead to the contamination of straight-run cuts such as naphthas or heavy distillates, which are used as feedstocks for steam cracker and FCC units, respectively.
OLEFINIC FEEDS
The presence of arsenic in olefinic cuts results from the cracking units treating contaminated feedstocks. For example, in the FCC field, the treatment of vacuum distillates contaminated by Organo-arsenic compounds leads to polluted olefinic cuts.
In this process, the severe cracking treatment applied to the vacuum distillate in the riser can achieve the transformation of heavy Organo-arsenic compounds into hydrocarbons and arsine (AsH3). Referring to Table 2, it is obvious that arsine will be carried over to the FCC C3 cut.
The utilization of the propylene contained in this cut requires the selective hydrogenation of the remaining traces of methylacetylene and propadiene (MAPD) formed during catalytic cracking. The presence of AsH3, however, results in severe poisoning of the hydrogenation catalyst. This can be illustrated by an industrial case of a C3-cut gas phase hydrogenation unit on the U.S. Gulf Coast (Fig. 3).
The operation of a hydrogenation unit with an arsenic-free steam cracker C3 cut has a reference cycle length of 100. After injection of an arsenic-contaminated FCC C3 cut, the cycle length was drastically reduced to 20% of the original value.
The implementation of an arsenic guard bed (MEP 191, from Procatalyse) upstream of the hydrogenation section enabled the recovery of the original catalyst performance.
NONOLEFINIC FEEDS
Natural gas from certain fields in several regions-for example North and South Africa, Southeast Asia, and parts of the Middle East-is known to-be contaminated with mercury. Other regions are certainly affected, but less information is available.
GAS-PHASE HG REMOVAL
The two types of natural gas-dry and wet-require slightly different treatment procedures. Dry natural gas, containing small quantities of C2+ hydrocarbons, has been found to be contaminated with elemental mercury.
Wet natural gas (methane containing substantial quantities of C2+ hydrocarbons and entrained hydrocarbon liquids) may be contaminated with important quantities of organometallic mercury in addition to elemental mercury. The treatment of wet natural gas can be made easier by first eliminating the entrained liquids, using a demister unit, before mercury removal.
Separation of the liquid droplets containing the large majority of organometallic mercury facilitates mercury removal for two reasons:
1. The gas fraction contains only elemental mercury.
2. The operation of the mercury-removal unit will be purely gas phase, permitting much higher space velocities than those obtainable in the presence of a mixed gas/liquid phase.
In the latter operation mode, the space velocity must be reduced because of the liquid film layer, which will cover the trapping solid, thus greatly limiting gas diffusion to the captation sites in the trapping solid.
The implantation of a gas-phase mercury removal system requires one or several simple reactor units. It is recommended that natural gas containing minor amounts of entrained liquids be preheated to assure gas-phase operation in the mercury-removal unit.
Wet natural gas differs from dry gas in that it first must be passed through a demister and a heat exchanger to assure proper gas-phase operation. Recently the use of Procatalyse's CMG 273 mercury captation mass was successfully demonstrated in Southeast Asia on wet natural gas, despite a demister upset caused by significant liquid hydrocarbon carry-over to the mercury-removal unit.
Because of the mesoporous structure of this trapping solid, the liquid was quickly drained off of the mass, enabling the rapid recovery of initial activity. This would not have been possible if the trapping solid had been a conventional microporous carbon-based material (approximately 1,100 sq m/g; average pore diameter, 10 A).
GAS-PHASE AS REMOVAL
Arsine, whether alone or in conjunction with elemental mercury, can be removed readily with a trapping mass. To the authors' knowledge, no trapping mass other than Procatalyse's can simultaneously remove As and Hg. The arsine-removal process is identical to the mercury-removal process described above.
LIQUID-PHASE REMOVAL
In addition to Hg and As being present in a wide range of cuts in liquid feedstocks (Figs. 1 and 2), both metals are present in diverse forms, which contributes to the difficulty of their removal.
Elemental Hg is readily captured on sulfur-based trapping masses in the gas phase. This technique is not easily transposable to liquid applications because of the solubility of elemental sulfur in the liquid feedstock. Thus, to capture elemental Hg, the trapping agent must be anchored to a support material.
Ionic (inorganic) Hg species in the form of Hg2+ or Hg22+ can be removed by ion exchange or reduced to elemental Hg using a reducing agent such as Sn(II). Ion exchange alone, however, cannot remove elemental Hg.
Similarly, the reduction of ionic Hg to metallic Hg by Sn(II) also requires a second agent to capture elemental Hg. Thus, a combination of both elemental and inorganic Hg species is more difficult to remove.
The removal of all Hg species from liquid hydrocarbon feedstocks is even more complicated because the majority of the Hg in these feeds is in organometallic form. Organometallic Hg cannot be removed by ion exchange because of the covalent nature of the Hg-C bonds.
In addition, the reduction of organometallic species by Sn(II) is not possible without a predigestion procedure. This is why the analytical measurement of Hg in liquids requires the addition of bromine to form ionic Hg, followed by the addition of Sn(II) to convert ionic Hg to metallic Hg.
Without the predigestion procedure, organometallic Hg remains intact. Thus, tin-based mercury trapping masses are not expected to be effective for organometallic Hg removal.3
Arsine generally is found in the light, vapor-phase fractions, from which its removal is not difficult. Organometallic As species, on the other hand, must be converted to a more reactive form to be efficiently captured.
The diverse Hg and As species present in raw condensates, or in crude oil or condensate cuts, would appear to present a very major problem. IFP has been able to avoid this problem, however, by submitting the feedstock to a simple, low-investment, two-step procedure, permitting the elimination of both As and Hg impurities with very high efficiencies.4
The first step in the liquid-phase Hg and As removal process requires passing the contaminant-containing feed over a hydrogenolysis catalyst in the presence of hydrogen. (Hydrogenolysis is the cleavage of a bond in an organic compound with simultaneous addition of a hydrogen atom to each fragment.5)
The catalyst causes the Hg-C and As-C bonds to rupture, generating metallic Hg and AsH3. The second step involves the simple chemical bonding of the latter two species to selective trapping masses.
A representation of this two-step process is shown in Fig. 4. The impure feedstock is mixed with hydrogen, then heat-exchanged to a temperature between 160 and 200 C., depending on the feedstock characteristics.
The charge is fed into the first reactor, where both catalytic hydrogenolysis reactions and As captation occur, using CMG 841. The now As-free feed is subsequently cooled to about 70 C. and fed to the second reactor, where Hg is captured on CMG 273 Hg-trapping solid.
The purified feedstock can then be subjected to a number of operations, which could have been adversely affected by mercury and arsenic.
A number of tests at the pilot and large-pilot scale (in cooperation with Mitsui Petrochemical Industries) have proven the efficiency of this process. A large pilot-scale test on a particularly difficult Southeast Asian raw condensate is cited as an example (Table 3).
A 3-month test was performed on a Southeast Asian condensate containing 66 ppb As and 1,800 ppb Hg.6 At the end of the test period, the levels of As and Hg were below 5 ppb (the detection limit) and 1.95 ppb, respectively.
The removal efficiencies are quite good: 92.4% for As, and 99.9% for Hg. This process is now ready for commercialization.
LIQUID-PHASE AS REMOVAL
Arsenic found in nonolefinic liquid hydrocarbons is present as organo-arsenic species, and thus must be converted to a more reactive form to be efficiently trapped. This can be achieved using the single-step process shown in Fig. 5.
Feedstock treatment on MEP 841 under hydrogen, at a temperature of 160-200 C., permits the total conversion of organo-arsenic compounds and the captation of arsenic. This process can be operated in both the gas and liquid phases.
Industrial units are in operation in Southeast Asia and the Middle Fast.
RECOMMENDATIONS
IFP recommends that nonolefinic steam cracker feedstocks be treated before entering the steam cracker unit. Failure to do so will severely aggravate the problem of Hg/As removal, in addition to contaminating the process internals.
To illustrate the difficulty that arises when an Hg-contaminated feedstock is not treated before steam cracking, Fig. 6 presents information on the distribution of Hg in the product streams exiting the separation train. Note that as much as 75% of the Hg entering the process may be retained by the process internals.
The C3 and C4 cuts are particularly contaminated. It is believed that the acetylenic species present in these cuts are responsible for the carry-over of Hg in organometallic form.
It is clear that the treatment of the crude feedstock is less capital intensive than separate treatment of each of the product streams.
ECONOMICS
Arsenic removal from FCC C3 cuts and mercury removal from natural gas are existing, well-known processes. The cost of removal of the impurities for these two processes is based almost exclusively on the quantity of the trapping agent required for operation.
Mercury and arsenic removal from nonolefinic liquid hydrocarbons is more capital-investment oriented because these processes require heat exchangers and hydrogen addition.
The process economics for the removal of arsenic and mercury from a contaminated condensate are shown in Table 4. The process is based on 138 tons/hr of feedstock containing 80 ppb As and 300 ppb Hg. The economics were calculated using an exit temperature of 70 C. and expected purified-feedstock Hg and As levels below 2 ppb, for a lifetime of at least 3 years.
The capital investment for a newly erected 1991 Gulf Coast-location unit, engineering excluded, is $2.85 million. The estimated catalyst/trapping solid inventory cost for a 3-year lifetime is $1.45 million.
The process investment required for As removal from 127 tons/hr of contaminated diesel oil is shown in Table 5. The contaminated feedstock is exempt from Hg, but contains 180 ppb As. The treated diesel oil exits the arsenic-removal process at 90 C. with an As content below 2 ppb.
The engineering-excluded capital investment for a newly erected 1991 Gulf Coast-location unit is $2.2 million. A 1-year catalyst/trapping solid inventory costs $0.51 million.
The current costs of natural gas condensate and diesel oil are approximately $200/metric ton. The annual treatment cost per ton during the 18-month payout period amounts to $3.12 for condensate and $3.06 for diesel oil (Table 6). This represents 1.5% of the market price of the contaminated feedstocks. As more refiners and petrochemical producers become aware of the problems associated with mercury and arsenic-contaminated hydrocarbons, the use of these materials will be severely restricted.
The future use of mercury and arsenic-contaminated condensates, such as those found in Southeast Asia (most notably in Indonesia, Malaysia, and Thailand), will require a 2% reduction in their market price, with respect to uncontaminated feeds, to render their treatment attractive.
ACKNOWLEDGMENT
The authors wish to thank Y. Shigemura and T. Hasegawa from Mitsui Petrochemical Industries for their cooperation during pilot plant experiments. They also wish to thank Gary Stephens from IFP Enterprises Texas Inc. for helpful discussions.
REFERENCES
1. Frenken, P., and Hubbers, T., Paper 27a, AIChE Spring National Meeting, April 1991, Houston.
2. English, J. J., Paper 74a, AIChE Spring National Meeting, April 1991, Houston.
3. European Patent No. 433677-A (1989), Calgon Carbon Corp.
4. U.S. Patent No. 4,911,825 (1990), Institut Franais du Ptrole.
5. The Condensed Chemical Dictionary, 7th edition, Reinhold Publishing Corp., New York, 1966.
6. Shigemura, Y., Hasegawa, T., Cameron, C. J., Sarrazin, P., Barthel, Y., and Courty, P., "Complete Arsenic and Mercury Removal from Liquid Hydrocarbon Feedstocks," Third International Petrochemical Conference, Sept. 19-20, 1991, Singapore.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
