Mercury Removal Al Goethe GPA_paper 2007

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State of Mercury Removal Technology

Tom Ruddy, Kent Pennybaker, RCEAl Goethe, Washington Group International, Inc.

Presented at the 86th Annual GPA ConventionMarch 12, 2007San Antonio, TX

Abstract

Mercury occurs in many gas plant streams in elemental (metallic), organic and

inorganic form. Although the reasons may vary, in most cases the presence ofthese mercury compounds cannot be tolerated and they must be removed.

Mercury will attack brazed aluminum type heat exchangers in cryogenic facilitiesand can lead to catastrophic failures. Mercury presents a health hazard whenvented to atmosphere such as in glycol or amine regenerator vents. In itsinorganic form, dissolved in aqueous streams, it is an environmental hazardwhen discharged through a waste water stream. Mercury also acts as a poison tomany catalysts in downstream facilities that process gas plant products.

GPA sponsored a survey of commercially available mercury removal

technologies to assist the facilities design and operations personnel inestablishing effective mercury removal strategies. Six vendors participated in thestudy and responded with process designs for eleven hypothetical mercuryremoval scenarios. These vendors represented a comprehensive range ofsuitable technologies. The survey included applications for removal of elemental,organic, and inorganic mercury from gas, liquid, and aqueous streams. Bothregenerable and non-regenerable designs were included.

This paper summarizes and compares the responses of the participatingvendors. The principal process design options are presented and explained.Estimated capital and operating costs are combined with project costs to

establish overall treating costs for each vendors technology.

The article also addresses other issues such as the influence of vessel costs,disposal costs, alternate process conditions, adsorbent life, and location oftreating in the overall gas processing scheme.


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Introduction

Mercury exists naturally in hydrocarbon reservoirs throughout the world. Thelevels of mercury found are typically low, yet even these low concentrations cancause significant problems. Mercury concentration varies significantly throughoutthe world and even from reservoir to reservoir. Table 1 shows maximum

wellhead concentrations of mercury found in various parts of the world.

Table 1Mercury in Natural Gas and Condensate1

Location Gas (g/m3) Liquids (g/kg)Europe 100 150 South America 50 120 50 100Gulf of Thailand 100 400 400 1200Africa 80 100 500 1000Gulf of Mexico (USA) 0.02 0.4 Overthrust Belt (USA) 5 15 1 5North Africa 50 80 20 50

Mercury occurs in gas plant streams in elemental (metallic), organic andinorganic form. Although the reasons may vary, in most cases the presence ofthese mercury compounds cannot be tolerated and they must be removed.

Mercury will attack brazed aluminum type heat exchangers and other equipmentutilizing aluminum components in cryogenic facilities. A number of equipmentfailures have been attributed to mercury corrosion. Mercury presents a healthhazard when vented to atmosphere e.g., in glycol or amine regenerator vents. Inits inorganic form, dissolved in aqueous streams it may be a health hazard whendischarged through a waste water stream. Mercury in production sludge presentsa disposal problem. Furthermore, mercury may act as a poison to catalysts indownstream facilities that process gas plant products.

The levels of mercury compounds are typically very low and the required removallevels are in the low ppb range, posing considerable analytical challenges.

A number of mercury removal options are available to the gas processor, basedon a variety of process schemes. This study is designed to assist the industry inthe selection of suitable economical and safe solutions.

Basic Chemistry of Treating

The mercury removal technologies in this paper fall into one of three broadcategories: (1) sulfur impregnated activated carbon, (2) metal sulfides dispersedin a solid carrier, and (3) molecular sieve technology.

1. The activated carbon technology removes mercury via the reaction:

Hg + S HgS


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The sulfur is deposited in a porous support such as activated carbon pellets.Mercury in the process stream reacts with the sulfur to form mercuric sulfidewhich remains on the support.

2. Metal sulfide technology removes mercury via the following reaction:

Hg + MSx MS(x-1) + HgS

In this technology, metal sulfides (MSx) are dispersed in an inorganic support oron activated carbon. Mercury reacts with the metallic sulfide and is trapped asHgS on the trapping material.

The reactive metal can be supplied with the reactive sulfide present or it can beformed in situ by reaction with H2S present in the hydrocarbon being treated.

3. Molecular sieve technology removes mercury via amalgamation with silver.The silver is placed on the outside surface of a dehydration molecular sieve

pellet. Dehydration and mercury removal are achieved simultaneously in aregenerable system.

Regenerable vs. Non-regenerable Systems

The activated carbon and metal sulfide technologies cannot be regenerated insitu. Activated carbon must be sent to a landfill or sent to an incinerator followedby mercury condensation. The metal sulfides can be sent to landfill, but alsohave the option of being recycled through metal smelting processes.

The molecular sieve systems are regenerated with hot gases which drive themercury off of the sieve and into the regeneration stream. At the end of the

sieves life cycle, it can be disposed of as non-hazardous waste. Mercury mustbe removed from the regeneration gas to satisfy the scope of this study, but thismay not be required in many practical applications.

Design Basis

Thirteen cases were offered for evaluation and are detailed in the following designbasis. There are four Gas Feed Stream Cases, six Liquid Hydrocarbon StreamCases, and three Other Cases.

In each case, mercury is removed from the process stream to a required level.

Cases

The cases for evaluation are divided into three tables on the following two pages.Table 1 lists the Gas Feed Cases. Table 2 lists the Liquid Hydrocarbon treatingcases. Table 3 lists the Other Cases which involve treatment of plant feed separatorwater and glycol vent streams.


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For non-regenerative systems, recovered mercury is assumed to be sent to a landfillor other appropriate site.

For regenerative systems, recovered mercury is not assumed to be re-introducedinto product streams for final disposal. Inlet gas from downstream of the adsorber

may be used for regeneration. As with non-regenerative systems some form ofrecovery is required, and recovered mercury is assumed to be sent to a landfill orother appropriate site.

In the gas and liquid feed cases, mercury contamination is listed in parts per billionby weight. In the case of molecules that include components other than Hg, the basisis the mass of the mercury, not mass of the molecule.

Tables 1, 2, and 3 on the following pages present the details of each case.

Table 2: Gas Feed Cases

Component Case 1Mol%

Case 2Mol%

Case 3Mol%

Case 4Mol%

Nitrogen 0.56 0.56 0.56 0.56Carbon Dioxide 2.00 2.00 2.00 2.00Methane 88.35 88.35 88.35 88.35Ethane 5.10 5.10 5.10 5.10Propane 2.03 2.03 2.03 2.03I-Butane 0.66 0.66 0.66 0.66N-Butane 0.38 0.38 0.38 0.38

Pentanes 0.46 0.46 0.46 0.46Hexanes and heavier 0.46 0.46 0.46 0.46

Total 100.00 100.00 100.00 100.00Hgelem. Content, ppb (wt) 90 90 90 90Water 0.00 0.00 saturated saturated

Temperature, 0F 80.0 80.0 80.0 80.0Pressure, psig 940.0 940.0 940.0 940.0

Flow Rate, MMSCFD 50.0 400.0 50.0 400.0Hg Outlet Spec, ppb (wt) 1.0 1.0 1.0 1.0


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Table 3: Liquid Hydrocarbon Cases

Component Case 5Mol%

Case 6Mol%

Case 7A, 7BMol%

Case 8A, 8BMol%

Stream Type PropaneProduct

PropaneProduct

Nat. Gasoline Nat. Gasoline

Carbon Dioxide 0.00 0.00Methane 0.00 0.00Ethane 2.50 2.50Propane 96.00 96.00I-Butane 1.00 1.00 0.20 0.20N-Butane 0.50 0.50 1.50 1.50Pentanes 0.00 0.00 25.00 25.00Hexanes and heavier 0.00 0.00 73.30 73.30

Total 100.00 100.00 100.00 100.00Hgelem. Content ppb (wt) 1000 1000 4000 4000Hgorg. Content ppb

1 (wt) 0.0 0.0 1000 1000

Water 0.00 0.00 0.00 saturatedTemperature, 0F Bubble point Bubble point 120.00 120.00Pressure, psig 250.00 250.00 100.00 100.00

Flow Rate, GPM 50.0 500.0 50.0, 500.0 50.0, 500.0Hg Outlet Spec ppb (wt) 0.1 0.1 500 500

Note 1: Organic mercury may be assumed to be dimethyl mercury

Table 4: Other Cases

Case 9: Water from Plant Feed Separator

Flow Rate: 100 gpmPressure: 1000 psig

Temperature: 70 FSalt Content (as CaCO3): 10% (wt)Mercury (Salt) Content: 100 ppb (wt)Mercury (elemental, carry over): 20 ppb (wt)Outlet Specification: 0.1 ppb (wt)Hydrocarbon Content: 40 ppmv

Case 10: Glycol Still Vent Stream (condensed)

Water Flow Rate: 1 gpmPressure: 20 psigTemperature: 100 FMercury content (elemental): 50 ppb (wt)Outlet Specification: 0.1 ppb (wt)


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Case 11: Glycol Still Vent Stream (uncondensed)

Flow Rate: 10,000 scfdPressure: 1 psig

Temperature: 100 FMercury Content (elemental): 50 ppb (wt)

Outlet Specification: 0.1 ppb (wt)

Results and Conclusion

Economic Analysis

Capital Costs

The equipment costs and installation factors were estimated for each equipmentitem using River City Engineerings (RCE) cost estimating experience and database. The installation factor applied includes miscellaneous costs such astransportation, site clearing, construction permits, on-site fabrication, erection,piping connections, instrumentation and controls, and other related constructionactivities. The cost of the first fill of adsorbent along with its own nominalinstallation factor was included.

Equipment sizes were developed from the vendors equipment specificationsprovided for this study. The vessel sizes were vetted to ensure that sizes foradsorbent beds included space for support balls and inlet distribution. Theresulting vessel size was used to establish the weight of steel which is used toestimate the cost for the vessel. An assumption was made on the percentage oftotal weight due to nozzles and connections. Carbon steel was determined to beadequate for all vessels. The installation factor was based on cost, size, and

orientation. Vessel wall thickness was limited to 4 inches.

Heat exchanger duty requirements were checked against vendor specifications.The vendor supplied exchanger areas were used to estimate equipment cost andinstallation factor. All exchangers were carbon steel tubes and shells.

Air coolers were sized using RCEs in-house air cooler sizing program. Allcoolers were assumed to be forced draft. The equipment cost and installationfactor were based on the cooler bare tube surface area. All air cooler tubes werecarbon steel. No cooling water was assumed available (as dictated in studybasis), so in some instances where vendors had indicated the use of coolingwater for cooling, an air cooler was utilized. In cases where the vendor did not

specify a process outlet temperature, the temperature was set at 120 F using100 F air at sea-level.

Fired heaters were assumed to be direct fired cabin-type heaters and the vendorsupplied duty was used to estimate the equipment cost. All fired heaters wereassumed as carbon steel. No steam was assumed available (as dictated in studybasis), so in some instances where vendors had indicated the use of steam forheating a fired heater was utilized of the same duty. For cases where only a


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minor temperature increase is necessary, the heating cost could be considerablylower in practical application if other heat sources are available.

Where applicable the vendor-provided compressor and pump sizing waschecked to ensure head requirements were sufficient for controls, piping, andother typical design tolerances. All compressors and pumps were electric motor

driven with carbon steel cases. Pumps were spared, compressors were notspared. All pumps were specified as API pumps with tandem seals. Costs werebased on horsepower, flow, and head parameters.

The installed major equipment costs were sub-totaled and the factors shown inTable 5 were applied to arrive at the total installed cost (capital cost). The factorsin Table 5 were applied to regenerable and non-regenerable technologiesequally. The regenerable processes will often involve simultaneous dehydrationin the same vessel. This report did not account for any differences in installationfactor that may result in the combined dehydration and mercury adsorptioncases.

None of the vendors who responded in this study charge a license fee. Thecontingency was applied to the sub-total of the major equipment cost plus thegiven factors.

Table 5Capital Cost Applied Factors Applied to Installed Equipment Costs

DescriptionFactoredPercent

Drains, small equipment 10%

Engineering 15%

Project Management 10%

Contractors Fee 10%

Owners Cost 2.5%

Contingency (of sub-total plus aboveitems)

15%

Operating Costs

Corresponding operating costs were developed for each process. The operatingcosts include the annual costs for fuel, electricity, manpower, adsorbentreplacements, and material disposal.

It was assumed that the facility would operate 360 days per year. Normaloperating manpower was assumed to be 20% of fuel, electric, adsorbentreplacement, and disposal costs.


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Fuel gas requirements were estimated assuming a fired heater efficiency of 80%.The cost of fuel gas was assumed to be $5 per MMBtu.

Electrical requirements were estimated from the pump, compressor, and aircooler motor demands. Miscellaneous electrical demands for lighting,accessories, controls, and utilities were estimated to be 0.8 hp per thousand

dollars of capital costs. Electricity costs were assumed at 10 per kW-hr.

Using the vendor supplied estimate for adsorbent life, the replacement costs forthe adsorbent were annualized. This included the labor costs for removal of thespent adsorbent and installation of the fresh material. In cases with multipleadsorbent beds in lead-lag configurations, quoted adsorbent life refers to the leadbed or beds and the operating costs reflect the change out of the lead bed(s)adsorbent quantity.

Disposal costs for the spent adsorbents were provided by some of the vendorsas requested. Where disposal costs were not provided, a disposal cost of $2 perpound was applied, which was the highest vendor provided disposal cost.

Disposal costs ranged from $0.5 to $2 per pound for Hg contaminated adsorbent.

Several factors can have a strong influence on disposal costs such asenvironmental regulations or freight costs. These factors can vary widelydepending on the location of the mercury removal system and were notexamined in detail for this report.

At $2 per pound, disposal costs accounted for between 5 and 10 % of treatingcosts of nearly all cases. Doubling disposal costs effectively doubles thosefractions of total costs.

In one process a liquid Hg product stream is produced which must be disposed.

This stream could potentially be sold as a revenue producing stream if sitelocation, product rate, and demand were all favorable. However, for the purposesof this study it was assumed to be a waste stream. At an assumed disposal costof $5/lb, the impact on the economic performance was miniscule due to the smallamount of mercury involved, so the disposal cost was omitted from the analysis.

Some vendors take their material back for re-activation and recovery of mercury.However, this option was not pursued in this report.

A 15% contingency was applied to the sum of the above described operatingcosts. Where necessary, the conversion from Euros to US dollars was 1.18 $/.

Methodology

Each technology was economically evaluated using the estimates for capital andoperating costs. The present value of 10 years of operating costs was calculatedand added to the sunk capital cost to obtain the net present value (NPV) of thecost of treating for each vendor case. A unitized treating cost, either /MCF forgas treating or /gal for liquid treating, was then computed by dividing the NPVby the amount of gas or liquid processed over the same 10 year period. The


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outlet rates from the treating process that would factor in any losses such as fuelwere used in the treating cost calculation.

The net present value was calculated assuming a 10% discount rate over a 10year operating period. No escalation in costs of materials, labor, fuel, electricity,or disposal costs was applied.

Cost of Treating

Cases 1-4 Vapor

The cost of treating for the different cases by vendor is shown below in Table 3Afor the gas treating cases. The cost for treating dry gas ranged from 0.11 /MCFto 0.41 /MCF for non-regenerative processes. It was slightly higher for theregenerative process at 0.66 to 1.21 /MCF. The same costs in terms of $/lb Hgremoved are listed in Table 3B.

For treating of water saturated (wet) gas the range of treating costs was slightly

wider at 0.14 to 0.54 /MCF for the non-regenerative processes. Theregenerative process ranged from 1.09 to 1.81 /MCF and in addition toremoving the Hg it also dehydrates the gas to low levels. The cost of furtherdehydration, if required, for the non-regenerative processes should beconsidered when comparing Hg removal processes for wet gas.

Table 3AGas Treating Cost Comparison

Case 1 Case 2 Case 3 Case 4

50 MMSCFD 400 MMSCFD 50 MMSCFD 400 MMSCFDDry Feed Dry Feed Wet Feed Wet Feed

Vendor Type /MCF /MCF /MCF /MCF

A Metal Sulfide 0.22 0.18 0.22 0.18

B Carbon 0.22 0.11 0.22 0.14

C Carbon 0.15 0.11 0.36 0.24

D Metal Sulfide 0.41 0.33 0.54 0.42

E Mole Sieve 1.21 0.66 1.81 1.09


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Table 3BGas Treating Cost Comparison

Case 1 Case 2 Case 3 Case 450 MMSCFD 400 MMSCFD 50 MMSCFD 400 MMSCFD

Dry Feed Dry Feed Wet Feed Wet Feed

Vendor Type $/lb Hg $/lb Hg $/lb Hg $/lb Hg

A Metal Sulfide $490 $410 $490 $410

B Carbon $500 $240 $480 $310

C Carbon $340 $250 $810 $530

D Metal Sulfide $900 $726 $1,195 $930

E Mole Sieve $2,690 $1,470 $4,470 $2,420

The treating capacity has an expected effect on treating costs. The averageunitized treating cost (/MCF) was approximately 50% cheaper when treating400 MMSCFD versus 50 MMSCFD. The economy of scale applied to bothequipment (vessels, exchangers, etc.) and to adsorbent costs, which tend to beslightly cheaper on a unit ($/lb) basis in larger quantities.

For some processes there is little or no effect of treating dry or wet gas. Forothers the cost increased significantly. This indicates some adsorbents areaffected by water and others are not. This shows up in the wide range of treatingcosts seen for the wet cases over the dry cases.

For the regenerative process the capital costs are significantly higher than thenon-regenerative processes due to the added equipment used for regeneration.

This equipment is primarily the same as used in mole sieve dehydration. Also,the operating costs are significantly higher for the regenerative process over thenon-regenerative processes. This is due to the fuel and power requirements ofthe regeneration system.

Cases 5 8 Liquids

A comparison of the liquid product treating cases by vendor is shown below in

Table 4A. The cost for treating propane ranged from 0.17 /gal to 1.91 /gal andfor natural gasoline the treating costs ranged from 0.81 /gal to 11.09 /gal. Theregenerative process was very competitive with the non-regenerative processes.

The same costs in terms of $/lb Hg removed are listed in Table 4B.

Propane treating is cheaper due to lower Hg concentration in the study basis andthe assumption that all of the Hg is elemental Hg. For natural gasoline the totalHg concentration was higher (5000 ppbw versus 1000 ppbw) and it was


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assumed that some organic Hg (20%) was present in addition to elemental Hgwhich, as indicated by vendors responses, is more difficult to remove.

There was no effect of water on the treating costs for the natural gasoline treatingcases. All the vendors that responded showed identical solutions for wet and drycases. It can be assumed that water would similarly have no impact on propane

treating should it be water saturated.

The treating capacity does not have a large impact on the treating costs. Atenfold increase in capacity only reduces treating costs by approximately 10%.One of the reasons that the capacity has little effect on the treating costs is theoperating costs due to adsorbent replacement are quite high compared to capitalcosts. The adsorbent life for the liquid treating cases was reported as 0.5 year to1 year for the non-regenerative processes. Therefore, the adsorbent replacementcosts increase the operating costs to where they dominate the economics andthe effect of the economy of scale is reduced.

The regenerative process is more competitive for the liquid treating cases than

the gas treating cases. The above mentioned shorter adsorbent life is one of theprimary reasons that it is more competitive. The regenerative adsorbent life ismuch longer than the non-regenerative adsorbent and the associated fuel andpower requirements of the regeneration system are more equivalent with theadsorbent replacement costs of the non-regenerative process.

Table 4ALiquid Product Treating Cost Comparison

Case 5 Case 6 Case 7A/ 8A Case 7B/ 8B50 gpm 500 gpm 50 gpm 500 gpmPropane Propane Natl Gasoline Natl Gasoline

Vendor Type /gal /gal /gal /gal

A Metal Sulfide 0.18 0.17 1.44 1.33

B Carbon 0.28* 0.26* na na

C Carbon 1.91 1.77 11.09 11.05

D Metal Sulfide 1.04* 0.90* na 0.81

E Mole Sieve 0.44 0.32 1.79 1.51


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Table 4BLiquid Product Treating Cost Comparison

Case 5 Case 6 Case 7A/ 8A Case 7B/ 8B50 gpm 500 gpm 50 gpm 500 gpmPropane Propane Natl Gasoline Natl Gasoline

Vendor Type $/lb Hg $/lb Hg $/lb Hg $/lb Hg

A Metal Sulfide $490 $470 $540 $500

B Carbon $750 $710 na na

C Carbon $5,130 $4,750 $4,170 $4,160

D Metal Sulfide $2,800 $2,420 na $270

E Mole Sieve $1,170 $860 $670 $570

Water Cases

Produced water and glycol still overhead treating cases are compared by vendorin Table 5A. The same costs in terms of $/lb are listed in Table 5B. The numberof vendors who responded to these cases was very low. These casesrepresented some unique treating challenges that have not been fully integratedinto the major vendors repertoire.

Only one vendor replied with produced water treating costs. Based on this lone

response the cost for treating produced water was 0.65 /gal. Two vendorsresponded with information for treating a condensed glycol overhead stream. Thetreating costs ranged from 0.24 /gal to 1.22 /gal. Three vendors responded totreat the vapor off the glycol overhead vent. The costs ranged from 0.04 /SCF to0.10 /SCF. The average liquid treating cost (Case 10) is 0.09 /lb of watertreated, and the average vapor treating cost (Case 11) is 0.95 /lb. However,there is the cost of the condensing and water handling equipment that must befactored into any decision related to treating of glycol overhead streams.


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Table 5AWater Treating Cost Comparison

Case 9 Case 10 Case 11100 gpm 1 gpm 10 MSCFD

Produced Glycol Ovhd Glycol OvhdWater Condensed Vent (steam)

Vendor Type /gal /gal /SCF

A Metal Sulfide na na 0.10

B Carbon na 0.24* 0.04

C Carbon 0.65 1.22 0.05

Table 5BWater Treating Cost Comparison

Case 9 Case 10 Case 11

100 gpm 1 gpm 10 MSCFDProduced Glycol Ovhd Glycol Ovhd

Water Condensed Vent (steam)

Vendor Type $/lb Hg $/lb Hg $/lb Hg

A Metal Sulfide na na $409,000

B Carbon na $5,760 $185,000

C Carbon $38,710 $29,530 $199,000

Comments on Key Issues

Treating Level / Ability to test

Currently most of the technologies available are capable of driving mercury levelslow enough for aluminum equipment protection or for current productspecifications.

Vendors commented that mercury levels in liquids can be very difficult tomeasure reliably.

Regenerable process vendors claim they can drive mercury to lower levels thanthe other available technologies. This could become valuable if environmentalconcerns drive treating requirements lower than are currently required for entryinto pipelines or liquid product pools.


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Safety

Equipment suppliers are currently developing new alloys of aluminum that will bemore resistant to mercury attack. This may lead to less stringent requirements forgas phase treating. At the same time, environmental concerns may drive treatingrequirements in the other direction. This may drive regenerable processes to

avoid bypassing mercury into product gas streams.

Mercury attacks aluminum in a variety of ways including amalgamation, amalgamcorrosion, liquid metal embrittlement, and intergranular attack preferential toweldments2. Amalgam corrosion is particularly dangerous because it canpropagate with miniscule amounts of mercury. However, it requires the presenceof water to proceed. In general, the other modes of attack require pooling ofliquid mercury.

According to the Aluminum Plate-fin Heat Exchanger Manufacturers Association(ALPEMA) standards3, Aluminum alloys with high levels of magnesium aresusceptible to a rapid reaction of mercury with a magnesium-based secondary

phase. This attack can take place in the absence of water and may lead tomercury corrosion cracking.

ALPEMA points out that there are multiple options available for dealing withmercury containing gases. Obviously, mercury can be removed using thetechnologies discussed in this study. This may be combined with specialshutdown procedures such as nitrogen blanketing to restrict moisture or avoidingtemperatures above 100C for long periods. If operators choose to not removemercury, design features can be used which attempt to eliminate build up orpocketing of mercury. Depending upon the application, it may be possible tochoose alloys which are less susceptible to attack.

Impact of Process Conditions

The design basis of this study is obviously limited to a narrow range ofrepresentative conditions. In practice, temperature, pressure, and flow conditionsmay vary significantly from those used here.

Pressure can have a large impact on gas phase systems since it is inverselyproportional to gas density, which is inversely proportional to linear velocity, andthe minimum required adsorbent bed volume. Pressure does not changeadsorbent capacity since the mercury is irreversibly chemically bound to theadsorbent.

Temperature can have a greater impact by changing the equilibrium of mercuryadsorption. Both the chemical reaction and mass transfer proceed faster athigher temperatures. However, temperature resistance of the adsorbent mustalso be considered.

Higher overall flow rates lead to larger vessel sizes to maintain the samemaximum allowable bed effluent mercury concentration, since they directly scalewith contact time and capacity for a given amount of mercury removed.


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Similarly, increases in inlet mercury concentration lead to larger vessels tomaintain the same life for the fixed bed systems (activated carbon and metaloxides). However, the regenerable systems may capture some economy of scalewhen combined with dehydration since they take place in the same vessel.

Location of Treatment / Operability

One of the key uses of this study is to understand where mercury removal shouldtake place in the overall gas processing stream. In the gas phase, removal cantake place upstream or downstream of dehydration (activated carbon and metaloxides) or with dehydration (regenerable sieve). Alternately, dehydration may notbe required at all. If gas phase removal is not required for equipment protectionor product gas requirements, treatment can take place in product streams.

The results of the gas phase portion of the study show that all of the fixed bedprocesses submitted are probably very competitive within the accuracy of the

study. When dehydration is also required, the regenerable technology is probablycompetitive as well and offers the lowest removal levels.

If gas phase treatment can be avoided, it may be cheaper to simply treat theliquid products. For liquid propane service, the activated carbon vendors are theleast competitive.

For natural gasoline service the metal sulfide and regenerable vendors havesimilar costs. Again, the activated carbon vendors do not appear to becompetitive in liquid service.

Only one vendor (activated carbon) offers a solution for treating produced water.

For condensed glycol effluent, only one vendor (activated carbon) offers asystem that meets the treating requirement. Three vendors offer competitivesolutions for treating uncondensed glycol vapor. An area of future investigationmay be to treat hot glycol vapors directly off the glycol still. Activated carbonvendors are open to pursuing this application, although the low partial pressureof mercury in this larger stream may make treatment impractical.

Adsorbent Life

The adsorbent life can have a large impact on the treating costs. Figure 1 showsthe impact on treating costs for representative processes using Case 1 as abasis (50 MMSCFD dry gas treating). Adsorbent life impact on the treating costs

is also somewhat dependent on the adsorbent type, but the overall trend for alltechnologies is very similar. For this case most of the vendors quotedapproximately a 5 year life for the adsorbent. In some cases very favorableconditions such as lower rates or Hg concentration may actually lead to extendedadsorbent life. Operating problems such as high pressure drop or bed channelingmay require operators to change out the adsorbent more frequently. If the bedlife is reduced to half the anticipated life, a 10 to 30% increase in treating costs(/MSCF) can be expected.


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Figure 1

Adsorbent Life Sensitivity on Treating Costs

0.50

0.75

1.00

1.25

1.50

1.75

2.00

0 2 4 6 8

Adsorbent Life (yrs)

NormalizedTreatingC

In this study, vendors generally targeted 5 year bed life in vapor cases althoughsome came out slightly higher due to residence time restrictions. In general, thecosts given for the vapor treating cases can be compared head-to-head due tothis relative uniformity of life. Regenerable beds are a special case; molecularsieve adsorbent typically lasts through 2 or 3 operating cycles of dehydrationgrade sieve or approximately 6 to 10 years.

The liquid treating cases have more uncertainty built into the analysis due tovarying life concerns. Quoted bed lives were typically 6 months to yeardepending on the vendor and case, but this can obviously have some impact ascapital expense (vessel size) is traded off against operating cost (frequency ofchange out). Again, regenerable technology is the exception. It is designed forthe same overall life as the vapor systems.

Conclusions

Mercury treating can be achieved in a cost effective manner in a variety of waysthat can be tailored to a variety of processing scenarios. The processor must

understand the driving force for mercury removal to choose the appropriatetechnology and location for treating.

Environmental concerns may some day play an even larger role in driving gasprocessors toward mercury treating even as new metallurgies obviate itsnecessity for equipment protection.

Gas processors have several options for gas phase cases, and can pursue arange of quotes and technologies that match their specific requirements. The


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activated carbon technologies are not as competitive in the liquid product treatingscenarios. Options for treating water streams are somewhat limited and thisshould be considered when choosing the location for mercury treating.

References

1. Wilhelm, S., McArthur, A., Removal and Treatment of Mercury Contaminationat Gas Processing Facilities, SPE/EPA Exploration & Production EnvironmentalConference, March 27-29, 1995, Houston, TX.2. Wilhelm, S., McArthur, A., Kane, R., Methods to Combat Liquid MetalEmbrittlement in Cryogenic Aluminum Heat Exchangers, 73rd GPA Convention,March 7-9, 1994, New Orleans, Louisiana.3.The Standards of the Brazed Aluminum Plate-fin Heat ExchangerManufacturers Association, Second Edition, 2000.

Mercury Removal Al Goethe GPA_paper 2007

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