May and June 1994
Reduce amine plant solvent losses Parts 1 &2 A systematic technical approach will identify and quantify losses into five categories E.J. Stewart and R.A. Lanning GAS/SPEC GAS/SPEC Technology Group
INEOS LLC As part of a Federal Trade Trade Commission mandated remedy to the merger of The Dow Chemical Company and the Union Carbi Carbide de Corporat Corporation, ion, INEOS plc was able to purchase both Dow’s Dow’s Ethanolamines and GAS/SPEC MDEA-based specialty amine businesses. This purchase became effective on February 12, 2001. INEOS LLC LLC was set up as the newly acquired acquired compa company, ny, which incl includes udes the t he GAS/ SPEC Technology Group. All the key Ethanolaminesan d GAS/SPEC personnel person nel were retained by INEOS LLC. All GAS/SPEC products, technology technology and know-how became the exclusive property of INEOS on a global basis.
Reprinted from HYDROCARBON PROCESSING ®, May 1994 issue, pages 67 67-81 and June 1994 issue, issue, pages 51-54. Copyright© 1994 by Gulf Publishing Co., Houston, Texas. All rights reserved. Used with permission.
PROCE SS TE CHNOLOGY
PART 1
Reduce amine plant solvent losses A systematic technical approach will identify and quantify losses into five categories E. J. Stewart a n d R. A. Lanning, Dow Ch emica l Co., Fr eeport, Texas
A
100 9 8 6 7 5 4 3 2
f 10 systematic approach to amine plant solvent-loss c s reduction begins with an accurate measurement M 1 M / of curr ent pla nt loss ra tes. To do th is, look a t long e n i term inventory and alka nolamine solvent purchases and m a calculate amine losses on a daily or hourly basis versus b l , s plan t production, i.e., lb a mine loss/MMscf of ga s tr ea ted. s o l If long-term da ta ar e not a vailable, makeup ra tes and ves e n i sel levels ca n be trended da ily to determine loss rat es. Once m A 1 a good estima te of tota l loss ra te is found, cat egorize individua l losses. 1 MEA 10% , 100 F N e x t , g a t h e r p l a n t d a t a f or c h a r a c t e r i zi n g l os s e s i n 2 MEA 15% , 100 F 3 MEA 20% , 100 F each ma jor category: 4 MEA 10% , 120 F 5 MEA 15% , 120 F • A complete laboratory an alysis of the tr eating solvent 6 MEA 20% , 120 F including heat st able salt a nd degrad at ion product levels. 7 MEA 10% , 140 F 8 MEA 15% , 140 F • P l a n t d e si g n d r a w i n g s 9 MEA 20% , 140 F • O p e r a t i n g c o n d i t i on s a n d p r o c ed u r e s , i . e . , f i l t e r 0 change-out procedures, a bsorber overhead temperat ures, 10 100 1,000 Pre ss ure, ps ia absorber pressures, trea ted ga s/liquid flow ra tes a nd solvent concentra tions. MEA vap orizat ion losses . Fig. 1. An a pproxima tion should be mad e for losses due to v a p o r iz a t i on , s o l u bi li t y, e n t r a i n m e n t a n d d e g r a d a t i on . The difference betw een estimat ed losses an d actu a l curAn importa nt loss-reduction considerat ion is t ha t current rent plant loss ra tes is at tributed to mecha nica l losses. system losses a re providing a purge for t he amine syst em. Individual mechanical losses a re identified by a t horough As losses are reduced, this built-in purge is removed and plant inspection a nd review of opera ting procedures. The conta mina nt levels increase. By ma inta ining periodic solvent analyses, buildup of confive cat egories of losses should ta minants in an amine system then be ran ked from highest to can be monitored a nd controlled lowest loss a rea. This ra nking A proble m and s olution . . . while reducing losses. esta blishes order of importa nce for equipment an d opera tional Solvent loss es in alkanolamine ga s and liquid trea ting plant s are ab out 95 MMlb/yr in the U.S. While some loss changes. VAPOR IZ ATION The most common ra nkin g of is exp ec te d in all op era tions , ext reme losses ca n ne ga These losses ar e a ssociat ed tively impa ct econom ics of op erating any amine unit. loss categories from highest to Unders tanding and co ntrolling amine loss es is an imporw i t h a l l a l k a n ol a m i n e t r ea t lowest in a ga s treating plant is ta nt as pe ct of s ucce ss ful plan t op era tion. 1 ment of gas str eams. They a re a To red uc e am ine solvent loss es in alkanolamine ga s mecha nical, entra inment, vapord i r e ct r e s u l t o f a l k a n o l a m i n e vapor pressure in the tr eating i z a t i on a n d d e g r a d a t i on . H o w - tre ating pla nts , a s ys te ma tic app roa ch is vital. Amine loss rate s have be come a more importa nt ec onomic face v er , w h e n a l i q u i d t r e a t e r i s to r in op e ra tin g ga s or liqu id tr e a tin g p lan ts du e to solution on the contacted gas part of the process, the ran king increas ed dis po sal co ncerns an d ch em ical co sts . stream. The amount of vapor Amine plant loss es ste m from vap orizat ion, solubility, becomes mechanical, liquid enphase alkanolamine is governed tra inment and solubility a s high- mec hanical, de grad ation and ent rainment . To cut loss es , b y o v e r h e a d o p e r a t i n g c on d i targe t the larges t loss area s and focus troubles hooting on l os s a r e a s . S m a l l e r lo s s es a r e de sign and op era tiona l chan ge s to red uc e losses . tions of the absorber, stripper due to gas entrainment, vaporand flash t ank vent. These are ization a nd degrada tion. the three main a reas of vapor HYDROCARBON PROCESSING
3
10
1 9 8
0.1 f c s M M / e n i m a 0.01 b l , s s o l e n i m A
7 6
7 6 5
5 4 3
3 4 2
2
1 f c s M M / e n i m a b l , s s o l e n i m A 0.1
1
1 DEA 10% 2 DEA 20% 3 DEA 30% 4 DEA 10% 5 DEA 20% 6 DEA 30% } 7 DEA 10% 8 DEA 20% 9 DEA 30%
0.001
9 8
0.0001 10
, 100 , 100 , 100 , 120 , 120 , 120 , 140 , 140 , 140
F F F F F F F F F
1
1 MDEA 30% 2 MDEA 40% 3 MDEA 50% 4 MDEA 30% 5 MDEA 40% 6 MDEA 50% 7 MDEA 30% 8 MDEA 40% 9 MDEA 50%
100 Pres su re, ps ia
1,000
0.01 10
, 100 , 100 , 100 , 120 , 120 , 120 , 140 , 140 , 140
F F F F F F F F F
100 Pres su re, ps ia
1,000
Fig. 2. DEA vap orization loss es .
Fig. 3. MDEA vap orizat ion loss es .
losses in alkan olamine t reating systems. P ara meters that govern the amount of vaporized amine ar e temperatur e, pressure a nd a mine concentr at ion. These para meters esta blish a n equilibrium between the amine v a p o r p r e s s u r e i n s ol u t i o n a n d t h e p a r t i a l p r e s s u r e o f a mine in the ga s strea m. As tempera tur e increa ses an d/or p r e s s u r e d ec r ea s e s , t h e a m o u n t o f g a s -p h a s e a m i n e i n c r ea s e s d u e t o h i g h e r v a p or p r e s s u r e e x e r t e d b y t h e alka nolamine on the gas. B ecause tr eated ga s is continuously being replaced by n ew ga s moving up the t ower, add itiona l amine must move into the ga s phase via va porization to maint ain equilibrium. Amine vaporization losses can be calculated for each solvent ba sed on vapor-pressure da ta of the specific amine an d the ga s stream temperature a nd pressure. Figs. 1 to 3 d e m on s t r a t e a m i n e v a p or i z a t i on l o s s e s p r e d i ct e d f o r monoetha nolamine (MEA), dietha nolamine (DEA) a nd methyldiethanolamine (MDEA). These were developed from pure-component va por-pressure da ta a ssuming idea l
solution beha vior (Ra oult’s La w). Since the gra phs ar e equilibrium based, a ctual losses will be lower tha n predicted. E s t i m a t e d l os s e s p er M M s c f o f g a s t r e a t e d b y a n a bsorber opera ting a t 700 psia a nd 120°F a re in Ta ble 1. L o s s es a r e s h o w n f o r e a c h s o lv e n t a t t y p i ca l o pe r a t i n g c on c e n t r a t i o n s . Th i s s h o w s t h a t M E A i s m u c h m o r e volatile than DEA and MDE A. Using the gra phs and specific plant conditions, an estima te of a mine losses ca n be obta ined for the absorber and fla sh ta nk vent. Gas f low from the flash t an k vent ma y be estimat ed if a direct measurement cannot be made. Because the reflux wat er returned to the system typically conta ins 1%to 5%amine, a cid gas exiting the str ipper is wa ter wa shed. In addit ion, flow of acid gas is usually a small ratio of the absorber gas rate. Therefore, vaporization losses from the st ripper a re usua lly sma ll. An estima tion of amin e losses can be ma de from Ta ble 2 for stripper amine va poriza tion losses. To reduce vaporization losses in a ny am ine syst em, conditions of the carry ing ga s/solvent equ ilibrium must be man ipulat ed to return a mine to the liquid phase. Major para meters to work with a re temperatur e, pressure and a mine concentra tion. Trea ted ga s coolers a re commonly used to return w at er to the amine system an d to reduce load on ga s dehydr a tion units. The cooler retu rns only a portion of the vaporized amine to th e main circulat ion system. However, by using a w at er-wa sh syst em, amine conc en t r a t i o n i s l ow e r e d a n d m u c h m o r e o f t h e v a p or i z e d amine can be recovered. The wa ter w ash ha s a low conc en t r a t i o n of a m i n e a n d a l ow a m i n e v a p or p r e s s u r e . Amine partia l pressure in the gas esta blishes a n ew equilibrium by forcing a mine into the wa ter pha se. The tw o most t ypical w at er-wa sh designs are a set of tra ys a bove the lean a mine feed point in t he absorber plus a separa te tra y, or a pa cked wa ter-wa sh vessel downst ream
Table 1. Es timated vaporization losses at 700 psia and 120°F
15% 30% 30% 50%
MEA DEA MDEA MDEA
0.54 lb/MMs cf 0.004 lb/MMs cf 0.035 lb/MMs cf 0.061 lb/MMs cf
Table 2. Amine loss estimation
MEA MDEA DEA
< 0.1 lb am ine/MMsc f ac id ga s < 0.01 lb am ine/MMsc f ac id ga s < 0.001 lb am ine/MMsc f ac id ga s
Reflux drum op era tion at 120 F and 25 ps ia
4
HYDROCARBON PROCESSING
Treat ed ga s out let
Trea ted ga s outlet
Was h wate r inlet
Was h wate r inlet
Lean amine inlet Trays or pa cking Trea ted ga s intlet (from abs orber)
Fres h wate r make up or st rippe r reflux
LC Amine was h return to sys tem (< 3.0% amine)
Fig. 5. Se pa rat e ga s wat er-wash syst em .
Gas inlet LC
1,000 Rich amine out let
MEA DEA MDEA
900 Fig. 4. Incorp ora te d was h tra y de sign.
of the conta ctor. Figs. 4 and 5 show these syst ems. Since t h e a m i n e s y s t e m w a t e r b a l a n c e o ft e n l i m i t s m a k e u p wa ter, stripper reflux can be used as a n interna l source of low-a mine wa sh w a ter. However, in H 2S syst ems, use caution because sour reflux wa ter ma y a ffect the treat ed ga s specificat ion.2 A gas tr eat ing s urvey completed in 1990 of West Texas a l k a n o l a m i n e pl a n t s s h o w e d a n a v e r a g e a m i n e lo ss r a t e o f 3 l b a m i n e /M M s c f d t r e a t e d g a s f o r M E A , D E A a n d MDE A products. Almost a ll of these plant s opera te a t elevated pressures, making va porization loss a small fra ction o f t h e t o t a l l os s r a t e . Th i s i n d i c a t e s t h a t e v e n t h o u g h some vaporization losses will a lwa ys occur, the bulk of amine losses occur in other loss categories. One area of high loss similar to vaporization is amine solubility in liquid hy drocar bons.
SOLUBILITY These losses are a ssociat ed with a ny a lkanolamine treating of liquid hydrocarbons. Similar to vaporizat ion losses, an equilibrium between amine in the hydrocarbon pha se an d the alka nolamine in aqueous solution is established. Amine in the liquid h ydrocarbon pha se is governed by t e m p er a t u r e , p r es s u r e a n d a m i n e co n ce n t r a t i o n a t t h e e x it i n g i n t e r f a c e of t h e t w o l i q u i d s . Th e s e p a r a m e t e r s esta blish the amine equilibrium between the two phases. In genera l, as t empera ture increases or pressure decreases, more amine is carried by th e hydrocarbon. As the hyd rocarbon at t he interface is replaced with new hyd roca rbon moving up the tower, more amine moves into the hydr ocarbon a nd is r emoved from t he syst em. In liq uid/liquid am ine treat ers, tempera ture a nd pressure typica lly operat e within narrow limits to maint ain the hydrocar bon as a liquid. The most importa nt pa ra meter to contr ol is am ine concentration. Amine solubility in hy drocarbon can be estima ted from physical properties to determine amine loss rates. Figs. 6 and 7 show solubility of amine in propane a nd buta ne.
800 700 w 600 m p p , y t i l 500 i b u l o s e 400 n i m A
300 200 100 0 0
10
20 30 40 Amine co nc ent ration, wt%
50
60
Equilibrium at 77 F and 300 ps ia
Fig. 6. Amine s olubility in propa ne.
These gra phs w ere developed using th eoretical liq uid/liquid equilibria ba sed on U niversal q ua si-chemical functional group activity coefficient (U NIFAC) para meters. The th eoretical predictions correlat ed closely wit h la bor a t o r y d a t a . Th e s e g r a p h s w e r e d e ve l op ed w i t h t y p i ca l liquid t rea ter conditions of 300 psia a nd 77°F.3, 4 The gra phs show the st rong effect amin e concent ra tion ha s on amin e solubility in hydr oca rbons. For a liquid poli s h i n g u n i t o p er a t i n g i n d e p en d e n t l y f r o m g a s t r e a t e r s , o pe r a t i n g a t a r e d u ce d a m i n e c on c en t r a t i o n i s n or m a l since amine-a cid loading is low a nd solubility losses can be reduced. In liquid treat ers opera ting w ith a regenera tion s y s t e m i n c om m o n w i t h a g a s t r e a t i n g u n i t , a v e r y l ow am ine strength ma y cause high loading or ga s absorber circula tion problems. In this ca se, a compromise must be HYDROCARBON PROCESSING
5
Trea ted hydroc arb on liquids outlet
1,000 MEA DEA MDEA
900 800
Trea ted hydro ca rbon liqu ids inlet (LPG or NGS from trea ter)
700 w 600 m p p , y t i l i 500 b u l o s e 400 n i m A
Typica lly pa cke d
Fres h wate r make up or st rippe r reflux Amine was h return to sys tem (< 3.0% amine)
Fig. 8. Coun te r-current wat er-wash syst em .
300 200 100 0 0
10
20 30 40 Amine co nce ntra tion, wt%
50
60
Equilibrium at 77 F and 300 psia
Fig. 7. Amine s olubility in but an e.
ma de. For solvents th a t ty pically operat e at 50%concentra tion, such a s MDE A a nd diglycola mine (DG A), we recommend a concentra tion of 40%. Operat ing liquid trea ters a bove 40%results in substa ntia l solubility losses. In a ddition to reducing operat ing a mine concentra tions, solubility losses in liquid-tr eat ing syst ems can be controlled by wa ter-wa sh systems. As with wa ter-wa sh systems on gas treat ers, the concentra tion of a mine in equilibrium with t he trea ted hyd roca rbon is reduced. Amine in the hydr ocar bon pha se establishes equilibrium with the wa ter-wa sh phas e. This new equilibrium moves the a mine back into solution for retur n to the ma in system. The count er-current , wa ter-wa sh vessel design (Fig. 8) a nd the co-current, w a ter-injected, in-line st a tic mixer design (Fig. 9) a re both successful in r educing solubility losses. The counter-current water-wash vessel has a hydrocarbon r etent ion time of 2 to 3 min. The outlet a mine concentr a tion in the wa sh is less tha n 3 wt %. A similar a mine concentra tion can be recovered in t he sta tic-mixer system. The ty pe of syst em chosen is cost dependent on the hydrocar bon flowra te an d operat ing system pressure. Initia l equipment cost ca n be recovered from amine sa vings. With va poriza tion an d solubility losses, the amount is s e t b y t h e a m i n e t y p e a n d p l a n t o p er a t i n g c on d i t i o n s . Table 3. Typical entrainment sources • Unde rsized tower diam et er for ga s flow • Ope rat ion of towe r be low de s ign pre ss ure • Trays op era ting at or ab ove flood ing • Plugg ed or da ma ge d tra ys • Unde rsized or plugg ed am ine dis tribut or • Dama ge d mist eliminato r pa d • Dama ge d knoc kout ves s el
6
Was h wate r inlet
LC
HYDROCARBON PROCESSING
S o m e l os s e s i n t h e s e t w o a r e a s w i l l a l w a y s b e p r es e n t . Vaporizat ion losses a re rela tively low u ntil low-pressure or high-temperat ure conditions ar e present. H owever, liquid treater solubility losses are typically high. Control systems for both losses are w a ter-wa sh syst ems. While va poriza tion and solubility losses are set by the physica l properties of the a mine an d opera ting conditions, entra inment, degrada tion and mecha nical losses center a round the equipment, operations, conditions and contaminants.
ENTRAINMENT (GAS TREATERS) These losses can be defined a s t he physical carr y-over of amine solvent into treated or a cid-gas streams. E ntra inment can be described as a mist or spra y, depending on droplet size for liquid-in-ga s dispersion. It ca n be described a s foamin g for ga s-in-liquid d ispersion. This is str ictly related to gas and liquid hydra ulics in the a bsorber. Foaming ty pically r esults from a combination of conta minat ion, solids a nd ga s hydra ulics in the absorber or str ipper. Liquid-in-gas dispersion (entrainment). This results from the forma tion of small a mine droplets. Diam eters from 0.1 to 5,000 microns a re ty pically formed a nd ca rried by t he ga s up th e column. Opposing forces acting on t h e d r o pl et a r e g r a v i t y v er s u s u p w a r d s g a s p r e s su r e a gainst the d roplet’s surfa ce. As t he a mine-droplet volu m e d e c r e a s e s b y r a d i u s c u b e d (r 3 ), t h e s u r f a c e a r e a decrea ses by radius squa red (r2). At some droplet s ize, its weight is insufficient t o overcome th e force of gas moving up the t ower. Therefore, a t sma ller droplet sizes, the ga s velocity must be reduced to prevent ent ra inment. 5 There ar e severa l symptoms of heavy ent ra inment losses i n g a s s y s t e m s . F i r s t i s o v er l oa d i n g of d o w n s t r e a m g a s knockout vessels. Even though the knockout vessel is designed to remove a n ormal a mount of entr ained a mine, high levels of entra inment w ill overload th e knockout system. Second, if knockout eq uipment is da ma ged or droplet size is small, entra ined am ine will move past knockout devices and collect in dehyd ra tion equipment a nd low places in gas t ra nsmission lines. Dehydra tion contamina tion can be checked in glycol units by pH a nd solvent a na lysis. These a re all common symptoms of a high a mount of entra inment, but identifying t he source is import a nt. Ta ble 3 lists typical entra inment sources in gas tr eat ers. To control these entra inment losses, maint a in low gas
velocities where only small dr oplets can be carr ied by the ga s. Sma ll droplets will not remove a grea t volume of solution from t he system. High entra inment losses ar e often at tributed to opera ting a n a bsorber above design ga s ra tes or below design pressure. The Sauders-Brown equation (Eq . 1) can be used to evalua te superficial ga s velocity for separ at ion of entra ined liquid in a 5-ft separa tion space above the top tray or with a mist elimina tor. The diameter design equa tion (Eq. 2) uses th is superficial velocity for evaluating t ower design.5– 7
ρL − ρ g V = K ρ g Then D
4G = πV
Trea ted hydroc arb on liqu ids inlet (LPG or NGS from trea ter)
Se pa rato r 15 min. rete ntion time for LPG 20 min. rete ntion time for was h
In-line sta tic mixer (co-current wate r was h)
LC Fres h wate r make up
1 /2
(1)
From reflux ac cu mulato r
Amine was h return to sys tem (< 3.0% amine)
1 /2
(2)
where V = D= G= rL = r g = K =
superf icial ga s velocity, ft/s vessel dia meter, ft g a s f l ow r a t e , f t 3/s a mine d ensit y, lb/ft 3 ga s dens ity, lb/ft 3 empirica l fa ctor, 0.167 for 5-ft spa ce above top tra y or 0.35 for wire mesh separa tor. In a ddition to ga s velocity, tra y design should be evaluat ed to determine percent flooding a nd slot velocities. O p er a t i n g t r a y s n e a r o r a b o v e f l o od i n g c a n c a u s e a n increased forma tion of droplets. Tra y design evalua tions a r e s u p p l i e d b y t h e v e n d o r . Am i n e d i s t r i b u t o r d e s i g n should a lso be checked as a possible source of mist forma tion. If mist elimina tor or knockout equipment is present, their capa city an d design should also be verified.7, 8 Mecha nical da ma ge to a w ell-designed system is a common source of spray. Equipment inspection can best determine if damage or plugging has occurred to trays or dist r i b u t o r s ca u s i n g t h e f or m a t i o n of a s p r a y o r m i s t . I n addition, any dama ge to the mist eliminator a nd knockout equipment can cause normally-ha ndled entra inment to become a high -loss problem. Norma l equipment solutions to liquid-in-ga s dispersion ta ke adva nta ge of droplet mass a nd tower ga s flow force. The most common solution is t o insert mist -eliminat or pads in the tower’s top and insta ll separa te downstrea m knockout vessels. The ba sic principle of th ese pad s is to provide a tortuous course for the ga s to tra vel and a large surfa ce ar ea for droplet impingement. Forwa rd momentum of the droplets is used to carr y t hem onto the mist-elimina tor surface as t he gas m akes a turn . Amine collects on the surfa ce, forming larger drops that fall back onto the tra ys or the bottom of the kn ockout vessel. A few examples of th ese sepa ra tion devices a re shown in Fig. 10. Wire-mesh mist pads ar e the most common, but ar e norma lly designed for a na rrow ra nge of ga s flows. If a bsorber gas r at es cha nge, consider replacing the mist pad for the new gas flow.
Gas-in-liquid dispersion (foaming). This resu lts fr om the forma tion of sta ble bubbles tha t build to a foam . The s u r f a c e a r e a t o w e i g h t r a t i o f or t h e s e s t a b l e b u bb l es i s high, a llowing t he gas t o ca rry t he foa m overhea d. A cert a i n a m o u n t o f f oa m o r f r ot h o n e a c h t r a y i s n o r m a l i n a l k a n o la m i n e t r e a t i n g . B u t t h i s f oa m i s n o t s t a b l e a n d quickly brea ks down int o solution. A foaming in cident occurs when a sta ble foam builds on one tra y up to the
Fig. 9. Co-c urren t wat er-was h s yst em .
Gas flow
Gas flow
A. Wave plate impingem ent separator
B. Vane -type impinge men t plate
Gas flow C. Wire-me sh mist eliminat or Fig. 10. Examp les of mist /s pra y elimination de vice s .
bottom of the next tr ay. This foam w ill move up the t ower an d carry over into downst ream equipment. Table 4 summarizes symptoms tha t identify a foaming problem. Foaming can be verified by an onsite shake test o r b y a r i g o r o u s b u b b l i n g t e s t o f 2 00 -m l s o l v e n t w i t h metha ne/nitr ogen through a bubbling stone. In both t ests, foam height a nd time required for the foam to break down into solution are measur ed. Foaming can be at tributed to three ma in para meters in alka nolamine systems: • A conta minant acting as a foaming initiat or • Solids sta bilizing the foam • High ga s velocity forming t he foa m. One or more of these parameters is needed for foaming. Amine conta mina nts such a s condensed hydrocarbons, orga nic acids, wa ter conta minant s a nd w ell-trea ting chemica ls can be checked by laborat ory a na lyses. Iron sulfide particles a nd other solids a re foam sta bilizers.9 Remedies for elimina ting foaming focus on identifying an d preventing solution conta minat ion, an d filtra tion to Table 4. Foaming symptoms • Overloading do wns tream knoc kout eq uipme nt • High or erra tic different ial tower pre ss ure • Dec rea se in out let CO 2 • So lution level bo unc ing in towe r • So lution level bo unc ing in flas h ta nk • Erratic stripp er fee d
HYDROCARBON PROCESSING
7
Rich amine Cross exc ha nge r Lean amine
Lean amine co oler To ab so rbe r
10 micron mec han ical filter
5 micron mec han ical filter Carbo n filter
Fig. 11. Lean am ine ca rbo n filter sch em e.
ma inta in solution qua lity. Ta ble 5 lists some typical foaming agents an d sources. Ma ny process unit opera tions ha ve been successful in p r e ve n t i n g c on t a m i n a n t s f r o m en t e r i n g a n a m i n e s y s tem. Several refineries use wa ter-wa sh systems on inlet ga s strea ms to remove organic a cids formed in cracker units. P orous-media filters on inlet ga s strea ms a re used for iron sulfide removal in sour-gas systems. Often, the process conta minan t can be removed by repair or modification of existing equipment. Oxygen can enter a feedg a s s t r e a m t h r o u g h v a p o r -r e co v er y u n i t s a n d t h r o u g h amine storage with out a gas bla nket. By modifying operat ion or equipment, oxygen conta mina tion ca n be greatly reduced. In a ddition t o separa tion systems to prevent conta minat ion, a mine solution q uality should a lso be mainta ined by mecha nical a nd carbon filtra tion. An a ctivated-carbon filter will remove many foaming a gents in an amine system, like condensed hydrocarbons, amine-degradation products a nd organ ic a cids. However, th e ca rbon filter can a lso intr oduce solids to the sys tem in t he form of carbon fines. In a normal design, a mecha nical filter is included on the outlet to remove an y fines before they ca n enter the circulat ing solution. A common design for a carbonfilter sy stem is shown in F ig. 11. Carbon-filtration systems can be placed either on the rich or lean a mine loop. They usua lly ha ndle from 10%to 100%of the circula ting solution. P lacement of t he carbon filter on the rich side is aimed at removing heavy conta mina tion before the a mine can foam in th e stripper and degra de in th e reboiler.10, 11 Table 5. Foaming agents and sources Organ ic ac ids Crac ked hydro ca rbo n Inlet ga s Makeup wate r Cond en se d hydro ca rbo ns Rich nat ural ga s Lea n amine coo ler tha n inlet gas Wate r co nta minant s Proc es s or city wate r Iron su lfide solids Inlet gas from so ur well formation Amine de gra da tion prod uc ts High reb oiler tem pe ratu re Oxygen co nta mination
8
HYDROCARBON PROCESSING
Mecha nical filt ra tion is used to remove solids. Solids ar e not generally foaming agents, but w ill sta bilize a foam once it is formed. An a mine system ma y ha ve a foaming initia tor present but the foam breaks down int o solution too quickly to caus e opera tiona l problems or losses. How ever, when solids are introduced to this system, the foam sta bilizes, causin g tr eat ing a nd loss problems. A high level of solids ca n a lso cause erosion da ma ge to equipment in high velocity a rea s. Mecha nical f ilters from 0.5 to 25 microns ar e used to handle 25%to 100%of the circulating solution. These filters ca n be placed in lean or r ich service ar eas. S o m e h i g h -l e v el s y s t e m c o n t a m i n a t i o n s c a n n o t b e fully controlled by mecha nical an d car bon f iltra tion. Antifoam a gents a re then used to contr ol foa ming. The most common types of agents are polyglycol or silicon based. H i g h m o l ec u l a r w e i g h t a l c oh o l s a l s o p e r f or m w e l l i n a mine systems. Anti-foam chan ges the a mine’s surfa ce tension t o inhibit bubble forma tion. Typically, ant i-foam ha s a t wo-ended molecular design. One end is at tra cted to the a queous phase, the other to th e hydrocar bon pha se. Thus, operat ion of the a nt i-foam a t t he solution’s surf a c e i s m a i n t a i n e d .12
Next mon th: Part 2 of a tw o-part series. How t o identify and prevent losses caused by entra inment in liquid trea ters, degra da tion and mecha nical leaks. Also included ar e two case hist ories t o demonstra te t he meth od’s effectiveness. LITERATURE CITED 1
Guru le, R. A., and M. Tashiro, Ch emical E conomics Handbook, Etha nolamines, SRI Internat ional, Menlo Pa rk, Calif., 1989. 2 Kohl, A. L., and F. C. Riesenfeld, Gas Purification, 5th Ed., G ulf Publishing C o., 1985. 3 Magnissen, T., P. Rasmussen, a nd A. Fredenslund, “UNIFAC Pa ramet er Table for Prediction of Liquid-Liquid Equilibria,” I ndustrial & E ngineeri ng Chemistry Pr ocess Design D evelopment, Vol. 20(2), pp. 331–339, 1981. 4 Aspen Technology, Aspen P lus, Aspen Technology, Inc., C am bridge, 1988. 5 Perry, R. H., and C. H. Chilton, Ch emical E ngi neers’ Handbook, 5th Ed., New York, McGra w-Hill, 1973. 6 Ba rker, W. F., “Evaluating S eparator P erformance for Hydrocarbon Streams,” Oil & G as J ournal, pp. 186–192, Dec. 27, 1982. 7 Ca mpell, J . M., Gas Conditioning and Processing, Cam pbell Petroleum Series, 1 V, Norman, Okla., 1979. 8 Schelman, A. D., “Size Vapor-Liquid Separa tors Quicker by Nomograph,” H ydrocarbon Pr ocessing & Petroleum Refiner, Vol. 42(10), pp. 165 –168, 1963. 9 Pea rce, R. A., S. G rosso, and D. C . Cringle, “Amine Gas Treating Solution Analysis: A Tool in Problem Solving,” C onference Proceedings from 59th Annual GPA C onvention, Houst on, Texas, M ar ch 17–19, 1980. 10 Keaton, M. M., and M. J . Bourke, “Activat ed Carbon System Cuts Foa ming and Amine Losses,” H ydrocarbon Pr ocessing, August 1983. 11 Bright , R. L., and D . A. Leister, “Gas Treaters Need Clean Amines,” H ydrocarbon Pr ocessing, December 1987. 12 Travis C hemicals, “Foaming Problems and Remedies for Ga s P rocessing Solutions,” Ca lgary, Alta, Travis C hemicals, Inc.
The authors Er ik Stewart is a senior research engineer for the Dow Chemical Co., Texas Operations. He has five years of experi ence with acid gas treatment technologies in the natural gas, ammonia and refining industries. Mr. S tewart has worked exten si vely on developing envir onmental technolo g ies for S O 2 and NO x removal. He holds a B S degree in chemical engineering from the University of Washing ton. A l L an ni ng join ed the Dow C hemic al C o. in 1982 and worked in eng ineering and production before moving to the GAS/SPEC Technology Gr oup in 1987. He c urrently works in G AS /SPE C sales for D ow, Houston, Texas. M r. Lanning has written several papers on H 2 S treatment usi ng liquid redox s ystems , been deeply involved in the suc ces sful introduction of the S ulFerox proces s and has worked extensively on geothermal H 2 S abatement technology. He g raduated with a B S deg ree in chemical engineeri ng fr om Lamar University in 1982.
PROCE SS TE CHNOLOGY
PART 2
Reduce amine plant solvent losses A systematic technical approach will identify and quantify losses into five categories
Trea ted hydroc arb on liquids outlet
Was h wate r inlet
LC
E. J. Stewart a n d R. A. Lanning, Dow Ch emica l Co., Fr eeport, Texas
A
systema tic approach to reducing a mine plant solvent losses begins by mea suring current loss rat es and ranking them according to loss category. The five areas of losses are: vaporization, solubility, degradation, entrainment a nd mechanical. P ar t 1 discussed the method to systematically reduce alkanolamine losses. It also included sections on how to identify a nd redu ce losses due to entra inment (gas t reat ers), vaporization a nd solubility.
Trea ted hydro ca rbon liqu ids inlet (LPG or NGS from trea ter)
Typica lly pa cke d
Fres h wate r make up or st rippe r reflux Amine was h return to sys tem (< 3.0% amine)
Fig. 8. Coun te r-current wat er-wash syst em .
ENTRAINMENT (LIQUID TRE ATE RS ) This has the sa me concepts a s ga s entra inment but is described as a n emulsion. B ecau se the higher density liqu i d h y d r o c a r b o n ca n e x er t a g r e a t e r f or c e on a m i n e d r o p l et s , f o r m a t i o n o f s m a l l d r o pl e t s w i l l ca u s e m u c h higher losses in liquid treat ers. Consequent ly, treat ers ar e designed for low velocities for both pha ses to a void sma ll a mine-droplet format ion. A common s ymptom of entra inment losses is the presence of a mine in low places in liquid lines or in downstrea m equipment, such a s filters. An obvious emulsion ‘rag’ lay er betw een hydr oca rbon a nd a mine phases in the liquid contactor is an indication of sma ll-droplet forma tion. Ta ble 6 lists gener a l liquid-tr eat ing design velocity parameters. Important parameters in amine entrainment a re a mine-distr ibutor orifice velocities, redistr ibutor orifice velocities and superficial velocities for both phases.13 Solving entrainment loss in liquid-treater systems requires a careful evaluation of treat er design specifications and inspection of internals. High contactor velocities due to poor design or da ma ge should be corrected. If entrainment persists, downstream separation equipment for liquid hydrocarbons is required. Sin ce the liquid density is close to the a mine, impingement devices are effective only on large dr oplets. Gra vity separa tion of liquid entra inment is much more successful. G ra vity separa tion is commonly used with a 10 to 20 min. hydrocarbon retention time at low velocities. This occurs either a bove the a bsorber inter phas e or in a sepa-
Table 6. General liquid treating design parameters Des ign parameter
Column diam et er Pa cking ma te rial Amine dis tribut or orifice veloc ity Amine superficial veloc ity Hydrocarb on s uperficial veloc ity Hydrocarb on dis pe rser orifice veloc ity
Des ign c riteria
15 gp m/ft 2 ma x. (tota l flow) Stee l or ce ramic 170 ft/min ma x. 60 ft/hr ma x. 130 ft/hr ma x. 1.00 to 1.25 ft/s
ra te downstr eam vessel. A coa lescer can w ork well in tan dem wit h a low-velocity separa tor to improve gra vity separ at ion of larger amine dr oplets. Coalescer pads provide a lar ge surface ar ea for the a mine droplets to collect a nd drop out of solution. Sepa ra tors/coa lescers wit h short hydr oca rbon retention times a re not as effective beca use the amine droplet momentum along a tortuous path in the coalescer does not d iffer gr eatly from the hyd rocar bon. Finally, the water-wash systems used for solubility losses are very useful in removing entrained droplets as w e l l . F i g s . 8 a n d 9 s h o w a g o od s e p a r a t i o n s c h em e f or removing entra ined and soluble a mine from a t reat ed liquid hydrocar bon str eam. HYDROCARBON PROCESSING
9
Treat ed hydroc arb on liquids inlet (LPG or NGS from trea ter)
Se pa rato r 15 min. rete ntion time for LPG 20 min. rete ntion time for was h
In-line st atic mixer (co-current wate r was h)
LC Fres h wate r make up
From reflux ac cum ulator
Amine was h return to sys tem (< 3.0% amine)
Fig. 9. Co-c urren t wat er-wash syst em .
Table 7. HSS species c ommon in amine systems
Nitra te Nitrite Format e Oxalat e Ace ta te Sulfate Sulfite Phos phat e Thios ulfate Thioc yana te
NO3 NO 2 CHO 2 C 2 O 4 C 2 H O 3 2 SO 4 SO 3 PO 4 S 2 O3 SCN
Est imat ion of entra inment losses in ga s and liquid systems is difficult. If knockout equ ipment is present, carr yover caugh t by t he equipment can be determin ed by closing the dump-system va lves and mea suring level versus time. Detailed field an alyses of entra inment in gas can be made using porta ble gas-testing la bs, but a slip-stream wa ter-wa sh system can be used for rough estimat ions. By ta king a measur ed slip stream of the trea ted gas or liquid through a water wash, the amine collected per volume of gas/liquid can be measur ed by tit ra tion. This va lue will be a combina tion of entra ined a nd va porized/soluble am ine. The ra tio of each t ype of a mine can be determined by using the previous gra phs.
DEGRADATION Amine-degra da tion losses a re difficult t o define in most alka nolamine systems. A broad definit ion of degra da tion is the chemical chang e of active alka nolamine. Amine does not leave the syst em but is no longer a vaila ble for removing CO 2 a n d H 2S. Since degrad at ion would include chemical breakdown of the amine into molecules tha t can and c a n n o t ca r r y a c id g a s , n o t a l l d eg r a d a t i on i s a n a c t i ve a mine loss. These degrada tion losses ar e often ha rd to determine because t he a lkalinity titr at ion for a mine concentra tion counts a ll basic material in solution a s a mine. Hea t-sta ble-sa lt (HSS ) format ion is another form of activeamine loss. The amine and a n a cid form a salt t ha t cannot be regenera ted in t he stripper.14, 15 Determinat ion of exact levels of degra da tion and HSS products requires a la bora tory a na lysis of the opera ting s o lu t i o n . Va r i ou s t e s t m e t h o d s c a n b e u s e d . G a s c h r o mat ography w ill determine amine-degrada tion products and concentra tions. HS S titr at ion with ion chroma togra10
HYDROCARBON PROCESSING
phy w ill determine the concentra tion an d t ype of a mine tied up as a non-regenera ble sa lt. The chemica l reactions of HSS format ion have been well documented. The ba sic principle is a rea ction of a cid with amine to form a n a mine salt in solution wh ich cannot be regenerat ed under norma l stripper operation. H2S a n d C O 2, by contra st, form a mine salts in solution tha t can be regenerat ed in t he stripper. Table 7 shows a number of HS S species that ar e commonly found in a mine systems. A rough species bala nce on th e amin e system is suff ic ie n t t o e s t i m a t e h ow f a s t a c t i v e a m i n e i s d e g r a d e d or complexed as a n H SS . With current levels of degra da tion products and HSS in the opera ting solution, assume tha t current syst em losses are providing a purg e at t he ra te of format ion. Then, from actua l loss ra tes obtain ed by inventory a nalyses, active amine loss by degrada tion is calculat ed from the purge rat e. For example, if 2 wt %HSS a nd degrada tion products is mainta ined in the system with a 1 lb/hr s olution loss r a te, t hen 0.02 lb/hr d egra da tion is occurring to th e active am ine. Solutions for chemical degra da tion focus on tw o area s. F i r s t , p r e v en t i n g t h e c on t a m i n a n t f r om c on t a c t i n g t h e amine by upstrea m separa tion or conta minant reduction at the source. For example, mechanical troubleshooting of vapor-recovery units can significantly reduce oxygen l e v el s i n f e ed g a s s t r e a m s . O x y g en c on t a m i n a t i on w i l l c a u s e h i g h d e g r a d a t i o n i n a l l a l k a n o l a m i n e s . An o t h e r example is the remova l of organic acids, typically a r efine r y p r ob l em , w i t h w a t e r -w a s h u n i t s o n t h e i n l e t g a s s t r e a m s . B y r e d u ci n g t h e o r g a n i c a c i d s co n t a c t i n g t h e amine, HS S format ion decreases. E v e n w i t h s e p a r a t i o n t e ch n i q u e s , s o m e a m i n e co n ta mina tion w ill continue. The choice of a mine a nd r eclaiming options becomes importan t for each a pplica tion. MEA systems t ypica lly require th ermal recla ma tion. This boils the a mine overhead a nd concentra tes salt ions in a sludge to be purged. Because DE A and MDE A are higher boiling-point amines, they cannot easily be thermally reclaimed with out degrading t he a mine. For MDE A solvents, preferential removal of HSS from the amine syst e m i s d o n e w i t h t e c h n o l og i e s i n c lu d i n g i o n e x ch a n g e resins, electrochemical cells an d va cuum distillat ion unit s. In each case, much of th e complexed a mine is rest ored an d returned to the system. However, in clean na tura l gas service, reclaim ing DE A a nd MDE A is not required.16, 17 Ca ustic treatment of am ine has been used for HSS problems, but th is is only a tempora ry solution. By add ing a stronger base tha n the a mine, caust ic substitutes in the HS S a nd frees the amine. However, this method can crea te man y ad ditional problems. The ca ustic treat ment can form sodium salts, some with low solubilities, and some very corrosive. These salt s ma y deposit a s solids throughout th e system. Therefore, only one or two a pplica tions of caust ic tr eat ment can be done before the a mine solution must be disposed of and r eplaced. I n a d d i t i on t o H S S f or m a t i on a n d c h em i ca l d e g r a d a t i o n , t h e r m a l d e g r a d a t i on o f a l k a n o l a m i n e ca n r e d u c e trea ting capacity. B eca use all treating a lkanolamines show accelerated degra da tion above 350°F, therma l degrada tion results from high skin t emperat ures on reboiler tubes or thermal-reclaiming tubes. We recommend a reboiler operation with an amine bulk temperature below 260°F. With hot oil and steam heating systems, risk of therma l d e g r a d a t i o n i s lo w s i n ce t h e h e a t m e d i a i s u s u a l l y n ot
operated at high temperatures. However, in fired-reboiler operat ion, the temperatur e of amine on the tube’s surfa ce can ea sily exceed 350° F. In f ired reboilers, forced circulation is often used t o ma inta in low skin tempera tur es. The rule of thumb is to m a i n t a i n a m i n e s k in t e m p e r a t u r e s b e t w e en 3 00 ° F a n d 325°F, and not exceed 350°F. For these temperatures a conserva tive design hea t flux of less t ha n 8,000 B tu/ft 2 of tube area is recommended. If therma l degrada tion is susp e ct e d i n a f i r e d r e b oi l e r, c a r e f u l l y e v a l u a t e f l u i d hydra ulics a nd hea t f lux in the reboiler t o determine the cause an d location of high skin tempera tur es.
MECHANICAL In the sa mple ra nking of a na tura l gas an d liquid-recovery plant , mecha nical losses were th e largest s ource of am ine loss. Mecha nical losses ar e defined as th e physical removal of solvent from t he closed circulation loop in the a mine syst em. This occurs a t t he solvent opera ting concentr a tion. Therefore, opera tion of higher-concentra tion solvents w ill incur higher am ine losses unless the volume of mechanical loss is reduced. Symptoms of mechanical l os s e s a r e v i s i b le a s a d r i p or a s p r a y f r om e q u i p m e n t . Ta b l e 8 s h ow s a p a r t i a l l i s t o f e q u i pm e n t a r e a s w h e r e mechanical losses ca n occur. L o s s e s t i m a t i o n i n t h i s c a t e g o r y i s t h e d i f f e r en c e between a ctual plant losses and the estimat ion of vaporization, solubility, entrainment and degradation loss. Individua l mecha nical losses must be identified by a plan t inspection a nd operat ion procedure review. Measurements of these losses a re ma de by bucket a nd st opwa tch or by titra tion and sump-flow measurements. Remedies for mechanica l losses focus on equipment correction. They should be a ddressed by engineering a nd plant personnel or the equipment vendor. Operational chan ges include rewr iting job procedures for meth ods of r e t u r n i n g a m i n e t o t h e m a i n s y s t e m . F o r e x a m p l e, a l l filter cha nge-outs should include a dr ain of the filter casing for return of a mine to the ma in syst em. The solution flush for pump seals should also be returned to the a mine s y s t e m . Th i s i s o f t e n a c co m pl i s h e d w i t h a d e d i ca t e d am ine sump. Case study 1. This is based on a liquid trea ting fa cility in Ca na da designed to process 22,000 bpd of etha ne liquids. Current operat ing losses a re estimat ed at 2.8 gpd on a 100%MD EA solvent ba sis. The low loss levels a re due to a downst ream w at er-wa sh system for the trea ted l i q u i d s t r e a m . Th i s s y s t e m i s s i m i l a r i n d e s i g n t o t h a t shown in F ig. 9. B y completing a species bala nce for t he wa sh syst em, recovered amine from entra inment a nd solubility in t he liquid conta ctor ca n be ca lculated. Wa ter-wa sh opera ting condit ions a re in Ta ble 9. The a mine recovered a t t he 22,000 bpd ra te is a bout 126.8 lb/d, i.e., 14.4 ga l of 100%a min e. This loss in a w elldesigned new plan t gives an in dication of the high levels of entra inment a nd solubility losses a liquid trea ter can h a v e . F o r o p er a t i o n a t 2 7 , 00 0 bp d , a m i n e r e c o ve r y increases t o 169.1 lb/d because a grea ter a mount of ent ra inment occurs at the higher hydrocarbon ra te. Most of the rema ining 2.8 gpd loss is at tr ibuted to mechanical loss, such as pump seal flushes. On a yearly basis, the wa ter wa sh system reduces amine plant losses
Table 8. Mechanical loss areas • Pipe flan ge /ga s ket co nne ct ions • Pump sea l flus hes or leaks • Pre ss ure ga uge /s am ple line purge • Freq ue nt filter ch an ge -out s • Filte r ca rtridge elem ents • Overhe ad fan co oler tub es • Wat er co oler tub es
Table 9. Water-wash ope rating c onditions
Etha ne rat es Wat er-wash rat e Amine co ncen tra tion Fres h ma keu p rat e
22,000 bp d 44 gp m 0.3 wt% 3.52 gp m
27,000 bp d 44 gp m 0.4 wt% 3.52 gp m
from 53,004 to 8,624 lb/yr. For a liquid tr eat ing pla nt, this level of loss contr ol is excellent .
Case study 2. This involves a la rge Louisiana refinery. This refinery is an integra ted system with multiple gas a bsorbers an d a liquid-trea ting unit . Historical solvent losses with MEA a nd MD EA were both in excess of 600,000 lb/yr. Conversion t o MD EA increa sed th e opera tin g cost a ssociat ed with t his level of amin e loss. The initia l loss ra nking identif ied entr a inment for both liquid and ga s treat ers as t he largest loss cat egory. Mist e l im i n a t o r s w e r e p la c e d i n e a c h a b s o r be r a n d a w a t e r wa sh system was insta lled on the treated liquid stream. The loss ra te w a s r educed fr om 640,000 lb/yr to 175,000 lb/yr. The w a ter w a sh r ecovered mu ch of the a mine loss due to solubility in the liquid hydr oca rbon strea m. End of series. Part 1, Ma y 1994, p. 67. LITERATURE CITED 13
14
15
16
17
DuPa rt, M. S., and B. D. Marchant, “Natural Ga s Liquid Treating Options and Experiences,” Conference Proceedings from 39th Annual La uran ce Reid G as C onditioning Conference, Norman , Okla., Ma rch 6– 8, 1989. The Dow Chemical Company, Gas Conditi oning Fact Book, Midland, Michigan, The Dow Chemical Company, 1962. Kennare, M. L., and A. Melsen, “Mechanisms and Kinetics of Diethanolamine Degradation,” I ndustrial & E ngineeri ng Chemistry Fundamentals, Vol. 24(2), pp. 129 –140, 1985. Ba con, T. R., J . V. Krohn, J . A. Lewno, an d R. A. Wolcott, “Alternat ive Economic Solutions for Amine Reclaim ing,” P roceedings of GP A Regiona l Meeting, Da llas, Texas, 1986. Ba con, T. R., S. A. Bedell, R. H. Nisw ander, S. S . Tsai, a nd R. A. Wolcott, “New Developments in Non-thermal Reclaiming of Amines,” P roceedings of the 38th Annua l Laurance Reid G as Conditioning Conference, Norman, Okla., 1988.
The authors Er ik Stewart is a senior research engineer for the Dow Chemical Co., Texas Operations. He has five years of experi ence with acid gas treatment technologies in the natural gas, ammonia and refining industries. Mr. S tewart has worked exten si vely on developing envir onmental technolo g ies for S O 2 and NO x removal. He holds a B S degree in chemical engineering from the University of Washing ton. A l L an ni ng join ed the Dow C hemic al C o. in 1982 and worked in eng ineering and production before moving to the GAS/SPEC Technology Gr oup in 1987. He c urrently works in G AS /SPE C sales for D ow, Houston, Texas. M r. Lanning has written several papers on H 2 S treatment usi ng liquid redox s ystems , been deeply involved in the suc ces sful introduction of the S ulFerox proces s and has worked extensively on geothermal H 2 S abatement technology. He g raduated with a B S deg ree in chemical engineeri ng fr om Lamar University in 1982. HYDROCARBON PROCESSING
11
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