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SPESPE 21507Recent Developments in Gas Dehydration andHydrate InhibitionA.A. Hubbard, John M. Campbell & CO.SPE Member

Copyright 1991, Society of Petroleum Engineers, Inc.This paper was prepared for presentation at the SPE Gas Technology Symposium held in Houston, Texas, January 23-25, 1991.This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper,as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflectany position of the Society of PetroleumEngineers, its officers, or members. Papers presented at SPEmeetings are subject to publication review by Editorial Committeesof the Societyof Petroleum Engineers. Permission to copy is restricted to an abstractof notmorethan 300 words. Illustrations may notba copied. Theabstract should contain conspicuous acknowledgmentof whera and by whom the paper is presented. Write Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836 U.S.A. Telex, 730989 SPEDAL.

ABSTRACTDehydration is an essential step in the processing of natural gas to meet pipeline specifications.Water removal is required to prevent condensation of an aqueous phase which can lead to hy-drate formation and corrosion in the gashandling system.The purpose of this paper is to review commercial natural gas dehydration processes andrecent developments which impact the installation and operation of these facilities.The paper will be divided into three sections 1) review and history of gas dehydration processes, 2) water-hydrocarbon equilibrium behavior and 3) new developments in gas dehydrationprocesses.REVIEW AND HISTORYThe removal of water from natural gas can beaccomplished in a number ofways. Commercialmethods currently employed include:

Adsorption (Glycol dehydration)Adsorption (Dry desiccant)Condensation (GlycoVmethanol injection)

References and illustrations at end of paper.263

The first two methods utilize mass transfer othe water molecule into a liquid solvent (glycosolution) or a crystalline structure (dry desiccant). The third method employs cooling tocondense the water molecule to the liquid phaswith the subsequent injection of inhibitor (glycoor methanol) to prevent hydrate formation.Early gas production systems used line heaters tokeep the gas above its water dewpoint. Since nocondensation occurred, hydrates and corrosionwere avoided. This was feasible since most pipelines were relatively short and fuel gas costs werminimal. With the advent of long distancehigher pressure transmission lines in the 1930's,more economical method of dehydrating naturagas was needed These early dehydration unitwere typically dry desiccant units employing alumina (bauxite) as the desiccant. Common tradenames included Plorite, Dri-O-Cel and Porocel.Following World War II the'natural gas transmission and gas processing industry grew rapidlyThe typical dehydration installation was still drydesiccant; however, silica gel replaced activatedalumina as the most popular desiccant. Silicgel had a higher capacity for water and couldalso be employed to remove heavier hydrocarbons (iCs+ ) from the gas, i f desired.

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2 RECENT DEVELOPMENTS IN GAS DEHYDRATION &HYDRATE INHIBITION SPE 2In 1950 the first commercial triethylene glycol(TEG) unit was installed by BS&B near EICampo, Texas. Glycol solutions (primarilyDEG) had been employed prior to this, but theywere generally unsatisfactory due to their limiteddewpoint depression and high DEG losses.TEG's lower vapor pressure made it a veryeffective desiccant since vaporization losses atthe absorber were insignificant and the TEGcould be easily regenerated to the high concentrations needed to meet pipeline water dewpointspecifications.By the mid 1950's glycol dehydration usinghighly concentrated solutions (98.5-99.5 wt%)TEG was the primary gas dehydration processused to meet pipeline specifications. It remainstoday the most popular method of dehydratingnatural gas.At the same time, glycol injection systems werebecoming a popular alternative to glycol dehydration. The demand for LPG was increasingrapidly. Most of the lean oil plants in NorthAmerica were being installed as or converted torefrigerated plants. Gas chiller temperatureswere often below OOp, which at the time wasnear the dewpoint depression limit of TEG systems. Glycol injection had been used for the inhibition of hydrates in LTS plants whichemployed valve expansion as the cooling mechanism. I t was an easy step to apply the sametechnology to refrigerated lean oil plants.The glycol injected was typically at 75-80 wt%ethylene glycol (EG) in water solution whichwas sprayed into the gas to insure adequate mix-ing as the gas flowed through the exchangertubes. The rich EG solution was then removedfrom the gas and liquid hydrocarbons in a threephase separator downstream of the exchangersor expansion valve. After regeneration the leanEG solution was returned to the gas exchangers.The mechanism for water removal in this process is condensation. The glycol solution is injected to prevent hydrate formation. Glycolinjection remains today a very common gas dehydration process. It is used in the G r o ~ g ~ nField in Holland and in many onshore facilities

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processing gas produced from the SoutNorth Sea.Dry desiccant was still employed as a ddration process in the 1950's and early 60's,the lower capital and operating costs associwith the glycol processes generally favoredapplication over dry desiccant. This changethe late 1960's with the advent of the tuexpander process, which was prompted bypetrochemical demand for ethane.Process temperatures in a turboexpander pcan reach -150 to -160Op. Dehydration to twater dewpoint levels was clearly outsiderange of any commercial gas dehydrationcess in the late 1960's. Some early plantsployed enhanced TEG units (e.g., DRIZO)subsequent methanol injection at critical poin the expander process. Others used dry dcants such as silica gel and alumina. Howeven the ability of these plants to reducewater dewpoint to sufficiently low levelsgenerally inadequate.Molecular sieves were first introduced to thdustry in 1954. However, their applicatiothe dehydration of natural gas was minimalthe late 1960's when very low effluentwatertents (less than 1 ppm) were required to mturboexpander plant feed specifications. S1970, molecular sieves have become thepopular method of dehydration upstream oftemperature process plap.ts. They are alsoin special applications such as high pressurehydration (above 2000 psia) and in somegas applications.Glycol dehydration, glycol injection or dry dcant make up virtually all commercial nagas dehydration processes employed in thedustry today. Other processes are availThree which merit discussion are calcium cide (CaCh), membranes. and proprietary proses. Some people classify calcium chloridedry desiccant, but there are significant diences between it and the adsorbents. Thedration of calcium chloride is non-regenerabcommercial applications; in fact, the produan aqueous calcium chloride solution. Bec

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2i507 ROBERT A. HUBBARD 3of this, eaCh units are typically batch processesand are applied in remote locations where fre-quent monitoring by personnel is not feasible.CaCh units were originally used on remote gas

in the early 1950's and are still used todayin a few areas, but they have largely been re-laced by one of the other processes.Membranes have received a great deal of public.,.ity in recent years promoting their potentialap-plication to gas dehydration. They have beenused effectively for the removal of CO2 fromnatural gas, air separation and for hydrogen re-covery in ammonia plants. The selectivity ofmembranes for water (relative to methane) ishigh, but outlet water concentrations in the resi-due stream must be low to meet pipeline specifi-cations (7 Ib/MMscf is equivalent to a molfraction of 0.00015). Since the driving force pro-moting mass transfer of the component acrossthe membrane barrier is ,the difference in itspartial pressure in the residue and permeatestream; water must be a very dilute componentin the permeate stream. This requires a largeamount of carrier (dilutent) gas to cross themembrane barrier with the water and exit thesystem in the low pressure permeate stream.Water content specifications have been met inmembrane systems designed to remove CO2from the gas, but in those cases the water wascoincidentally removed with the CO2 and suffi-cient C02 and methane existed in the permeatestream to dilute the water. To my knowledgemembranes have not been applied for the pri-mary purpose of natural gas dehydration.Proprietary solvents processes are also being ap-plied to gas dehydration. Institut Francais duePetrole (IFP) has proposed a new process,IFPEXOL@, which employs methanol as the liq-uid desiccant. The methanol is contacted withthe gas in an absorber where water is removedby a conventional physical absorption. The ef-fluent gas stream which contains a significantmount of methanol vapor is then refrigerated forhydrocarbon recovery. The vapor phase methanolis condensed and collected in the refrigerationplant where it is essentially immiscible with the

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liquid hydrocarbons. It is then regenerated andreused.Another proprietary solvent, Selexol, may alsobe used for natural gas dehydration. It has tradi-tionally been used for selective gas treating, busince it is a glycol (dimethyl ether of polyethyl-ene glycol) i t has a high affinity for water. Thisprocess, like membranes, is usually selected forother reasons but the water will be coinciden-tally absorbed with the acid gas and heavy hy-drocarbon components.WATER HYDROCARBON BEHAViOROne would think, with the long and generallysuccessful history dehydrating natural gas, thanew developments in this area would be minimal. In some respects this is the case; most bud-gets commit few funds to basic research intowater;.hydrocarbon equilibria. There are somenew developments, however, which haveprompted greater interest in this area.1. Saturated Water Content of Natural GasesPredicting the water content of natural gas isone of the routine calculations performed by en-gineers and operators. I t is arguably the mosimportant variable in the design of dehydrationsystems. For most gas systems the McKetta andWehe1 chart in the GPSA Engineering DataBook or the chart based on the work ofMcCarthyBoyd and Reid2 provide the standard for watecontent determination. These charts can beused to predict the saturated water content osweet, pipeline quality natural gas. They weregenerated from empirical data and for all practical purposes give identical results.Most of the recent work in water content correlations has been devoted to predicting the watecontent of sour gases, applications of equationof state to water content prediction and watecontents of gases above hydrate structures.Maddox3 presents an excellent summary owater content correlations for sour gases whichwill not be repeated here. In general, for acidgas concfntrations less than about 30% existingmethods ,5,6 are satisfactory. For higher acid ga

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4 RECENT DEVELOPMENTS IN GAS DEHYDRATION &HYDRATE INHIBITION SPEconcentrations (above 50%), particularly athigher pressures, existing methods can lead toserious errors in estimating water contents.Equation of state methods typically overestimatethe water content in this region, when comparedto the limited experimental data. Hand methodstypically underestimate water contents.Equations of state have been only partially successful in modeling water hydrocarbon behaviorin sour gas systems. One reason is the inherentlimitations in the application of a cubic equationof state to highly non-ideal systems. The secondis that the binary interaction parameters forH20-C02 & H20-H2S were developed from binary data. The water contents of pure H2S &C02 show anomalous behavior at high pressures.This behavior is not as dramatic when the H2S& C02 are components in a natural gas. Thethird limitation is related to the second in thatvery little experimental data is available onwater contents of natural gases with high acidgas concentrations.Perhaps a bigger issue in predicting saturatedwater contents is knowledge of the system temperature. A 10F [5.5C] temperature increasefrom 80-90oF in a sweet natural gas at 1000 psia[6900 kPa] raises the saturated water content by36%. It makes little sense to quibble about theaccuracy of the water content model when theeffect of a small change in temperature is 2 to 3times the standard deviation of the model.The final contemporary issue regarding watercontents of gases is predicting the water contentabove hydrate structures. It has long been recognized that water content correlations like theone shown in Figure 1 are valid only if the condensed phase is liquid water. I f the condensedphase is a hydrate (or ice) crystal, the water content is lower. This is not a significant issue formost units dehydrating to pipeline or field specifications. First, the relationship between waterdewpoint and water content from a correlationlike Figure 1 is valid when the dewpoint temperature is relatively warm, i.e., near the hydratetemperature, or when any portion of the condensed phase is liquid water. Second, pipeline

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water specifications are stated in water cone.g., Ib/MMscf or mglstd m3 In these caseactual water dewpoint is irrelevant.However, in those cases where the gas isrefrigerated to low temperatures and the otive of the dehydration process is to prevenor hydrate deposition in the process, thetionship between water content and wdewpoint is significant. This is particularlywhen the dehydration process is TEG absorsince the required minimum concentratiothe lean TEG depends upon the water cospecification.Figure 27 shows the water content of a simuPrudhoe Bay gas at 650 psia [4500 kPa] vs.perature. This workwas done for ARCO Aprior to the installation of the gas processingties at Prudhoe Bay. Note that at -4QOp [-and 650 psia [4500 kPa] the water contentgas in equilibrium with a hydrate isIb/MMscf [2.1 mglstd m3]. I f one uses adard water content correlation based on mstable equilibrium with liquid water, thecontent is 0.32 Ib/MMscf [5.1 mglstd m ~ .difference may not seem significant, but thihave a profound effect on the leanTEG cotration required to meet the specification, win turn affects the design of the regenerator2. HydratesHydrates were first observed experimentalSir Humphrey Davy in 1810; however, mothe research into hydrates has been perfoin the past 50 years. Hammerschmidt firsttified hydrates as the primary cause of pluin gas transmission lines in 1934.8 Sincetime the natural gas industry has committenificant resources to the understanding odrate formation and prediction of hyequilibria. Some early excellent studies odrates can be found in the references at theclusion of the paper.9,lO,1lKatz12 first proposed a method for estimhydrate formation conditions in the early 1This method, often called the "K" value meuses a vapor-solid equilibrium cons

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SPE 21507 ROBERT A. HUBBARD 5employed in the traditional dewpoint equation.

~ y i / K i = 1.0 at the hydrate point (1)e calculation is iterative in temperature oressure, but typically converges easily in a fewries. The result of the calculation is the theo

etical composition guest molecules in the hy-e structure.he Katz method was originally proposed as aentative method, but has persevered in essenially its original form. (Some of the K valueharts have been modified over the years.) Mostople recognize its shortcomings but it givesxcellent results, particularly on sweet naturalses with "typical" paraffin hydrocarbon compo

It is less accurate on gases with signifint non-hydrocarbon concentrations, gases withn unusual distribution of hydrocarbons and atigh pressures - above 1000 psia [6900 kPa].

&IIIJlirical methods have also been preented, ' but the most common hydrate prection techniques employed today are based onatistical thermodynamic models. Parrish andrausnitz15 proposed such a model based on theearlier work of van der Waals - Platteeuw.16hese provide the basis for most of the comter programs used to predict hydrate formation conditions.general, these thermodynamic based comer models are sufficiently accurate for the deign of most gas processing and transportationystems. Additional data is needed to confirmthese models in systems containing significantquantities of H2S.Historically, the lion's share of the hydrate reearch work has gone to predicting hydrate equilibrium conditions, typically the hydratedissociation pressure. Recent work has focusedon the kinetics of hydrate formation. Hydrateformation is a crystallization process which inolves multicomponent mass transfer to the crys-tal growth site. The time required for initialcrystallization to occur depends on several fac-tors: the degree of subcooling below the hydrateequilibrium temperature, the presence of artifi-cial nucleation sites, e.g., rust, scale, sand, etc.,

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and the degree of mixing. It has been observedin laboratory experiments that for a smalamount of sub-cooling the time for initial crys-tallization is several hours, sometimes days.Further, once the initial crystallization has begunadditional time is required for the ice crystals toagglomerate and actually block flow.Figure 3 shows the relationship between temperature and pressure in a constant volume cellwhere hydrate formation can be observed. Youcan see the degree of sub-cooling required tobegin significant hydrate crystallization. A sig-nificant pressure drop in the cell is observedwhen rapid crystallization begins.The actual hydrate equilibrium point reported inthe literature (and estimated by models) is thepoint at which the heating and cooling curves intersect. This is reported as the hydrate dissociation pressure.IFF, Norsk Hydro and several other organizations are involved in research to develop anew class of inhibitor which affects the rate ocrystal growth rather than lowering the hydrateequilibrium temperature. I f successful, it maybe feasible to operate gas transmission or flowlines well below the hydrate equilibrium temperature.Hydrate crystals may indeed form in these sys-tems but since they do not agglomerate to blockor plug the flow they are not a problem. Sloan1?has proposed a simple kinetic model to simulatethe crystal formation and growth.3. Hydrate Inhibit ionHydrate inhibition has already been introducedin the preceding paragraphs. As stated earliermost of the research work done today on inhibitors is directed to chemicals which affect therate of crystal growth rate. Classical inhibitorspreviously methanol, (mono)ethylene glyco(EG), and diethylene glycol (DEG) lower thehydrate formation temperature. In effect theyperform the same function as antifreeze. In the1930's Hammerschmidt18 first investigated theuse of inhibitors to prevent hydrate formation in

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6 RECENT DEVELOPMENTS INOAS DEHYDRATION. HYDRATE INHIBITION SPE 2natural gas pipelines. In his original paper hepublished the now famous equation for estimating the hydrate suppression in the presence ofan inhibitor.

where:AT= hydrate suppression, PXMeOH = mol fraction ofmethanol in the inhibitorsolution

where:x=mol fraction ofH20 in the inhibitosolutiona =activity coefficient for H2O inhibitosolution'AHp= heat of fusion of the hydrate, Btu/l

[kJ/kmol]R=gas constant, 1.987 Btu/lb mol-P[8.314 kJ/kmolK]T = syStem temperature, ~ , KTH= hydrate temperature with no inhibipresent, ~ , K

The activity coefficient, a, is back calcufrom experimental data. Temperature effecAHp are included in a, so a is not a true accoefficient bu t more a correlation constant."activity coefficient" is a function of temperand composition. This method is a validproach and gives excellent results whenpared with experimental data. Since littleexists above 50 wt% inhibitor concentratthe method should not be extrapolated bethis region.Computer models employing a statisticalmodynamic approach are also availabAgain, since little data is available on hysuppression using inhibitor concentrations icess of 50%, these models should be usedcaution in the high concentration region.As a practical matter, the weaknesses inmodels are not a serious problem. In lowperature inhibition the primary design critis adequate mixing of the inhibitor solutionthe gas. This typically requires inhibitor ition rates which are considerably higher tharates indicated by the hydrate suppremodel.One area where new experimental data is neis in the area of mutual solubilities of the aquphase inlubitor and the hydrocarbon phase.primmy interest are methanol solubilities inhydrocarbon phase and hydrocarbon solubi(particularly aromatics) in EG solutions. Tis limited data available in the public domathe MeOH-hydrocarbon system and virtual(4)

(2)xAT = M(1- x)

Figures 4 and 5 show the results of equations 2and 3 plotted against actual experimental datafrom GPA RR #92 for EG and methanol inhibition.20Maddox21 proposes a more thermodynamicallysound model using the equation:

-AHp(1 11n(ax) = ---T TH

where:AT=hydrate suppression, P fC]K == constant 2335 i fAT is in PK= constant 1297 if AT is in cM= molecular weight of the inhibitorx= weight fraction of the inhibitor in theaqueous solutionThe Hammerschmidt Equation is still widelyused to estimate inhibitor concentrations. It wasoriginally developed for low inhibitor concentrations, but has been applied over a much widerconcentration range than was originally intended. It givesgood results for methanol whenthe concentration is less than about 25 wt%. Itgives good results for the glycols at concentrations as high as 50-60 wt%. As Nielsen andBucklin19 point out, this apparent accuracy isless due to the legitimacy of the equation than to.compensating errors. For high methanol concentrations such as those required for low temperature inhibition in turboexpander plants, theHammerschmidt equation is clearly inadequate.Nielsen and Bucklin proposed an alternativeequation for these systems.

AT = -129.6ln(1- XMeOH) (3)

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E 21507 ROBERT A. HUBBARD 7available on th e EG-hydrocarbon system.

e former is important to accurately estimatehibitor injection rates, th e latter because ofvironmental limits on BTX emissions fromycol regenerators.EHYDRATION PROCESSESmmercial natural gas dehydration processesave changed little in th e past 20 years. Newrocesses, such as membranes and th e propriary schemes mentioned earlier in this paper,

been introduced bu t have no t made signifint inroads into th e business.rhaps the two most significant contemporaryues involve TEG systems. These ar e 1) TEG-ter equilibrium data and 2) hydrocarbon solulity (particularly aromatics) in TE G solutions.e first is important because TE G systems ar eeing employed today to achieve waterwpoints below -20Op (-29C) in a number ofations, including th e North Slope Alaska andhe North Sea. Th e lean T EG concentrations

in these units ar e often above 99.95% TEG (0.416 mol% H20). Accurate H20-G equilibrium data in this region is imperave for design and troubleshooting purposes.

e second issue is important from an environan d safety standpoint. In th e contactor,

G can absorb significant amounts of aromaticin th e gas. These aromaticsenezene, toluene, xylene, ethylbenzene) ar en released to th e atmosphere at t he regenertor. While these emissions ar e generally smalla mass basis, they have received a great dealattention from state regulatory agencies.nsequently, gas producers an d processors ar ecreasingly sensitive to this issue when

or operatingT EG systems.TEG-water Equilibrium Datauilibrium data for the TEG-water-natural gasstem have been investigated since the ~ 1940'swith the work of Wise et al., Porternd Reid,24 and Townsend2S Additional experintal data was gathered in the 1960's and 70's byuzillo,26 Worley,'Zl and Rosman.28 Th e most

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recent work in this area has been published byHerskowitz and Gotlieb29 and Parrish, et al.30Substantial deviatioIiS exist i n b ot h the measureddata and published correlations. One of the primary factors contributing to these discrepanciesis th e difficulty in accurately measuring waterconcentrations in the vapor phase above TEG-water solutions.In order to predict th e equilibrium behavior,most researchers simply extrapolated the measured data at relatively low TEG concentrationsto infinite dilution using an activity coefficientmodel.Although this treatment has been inaccurate, ithas been generally satisfactory for most dehydrato r designs because only a few equilibriumstages ar e required to achieve typical pipelinewater-content specifications. Hence the inaccuracies in the correlations have been compensated for in th e equipment design.This is demonstrated by th e fact that there areliterally thousands of glycol systems installedworldwide which adequately dehydrate the gasto pipeline specifications.However, for systems where th e outlet water

d e ~ i n t requirement is very low (less than -40Op[-40 .Cn, th e accuracy of th e water-TEG equilibrium data can have a significant effect on thesystem design and operating parameters. Inthese systems th e purity of t he lea n TE G is byfar th e most important variable in determiningth e outlet water content of th e gas.Most existing glycol systems installed in the past30 years have been designed by use of theScauzillo' or Worley equilibrium data. This isfine for field dehydration units meeting routinewater specifications, e.g., 7 lb H20/MMscf [110mg H20/std m1, but for extremely low waterdewpoints typical of North Slope or North Seaoperations, these methods have proven too optimistic.Both t he Ros man a nd Parrish correlations provide a better design i n t he low dewpoint regions.Th e Parrish correlation is recommended

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8 RECENT DEVELOPMENTS IN GAS DEHYDRATION &HYDRATE INHIBITION SPE 2because the activity coefficients are "anchored"to experimental data in the infinite-dilution region. In virtually all other correlations, the infi-nite-dilution values are extrapolated fromequilibrium data at much higher concentrationswith a van Laar-type activity coefficient model.The equilibrium concentration of water in thevapor phase above a water,:,TEG solution can beconverted to a dewpoint from any of the published water content correlations for natural gas.Figure 6, which is based on the Worley data, isone such figure. It may be found in the GPSAEngineering Data Book - Fig. 20-35.Figure 7 presents the same information, but isbased on the work of Parrish et al. Note the dif-ferences in equilibrium water dewpoints, particularly in the high TEG concentration range.At TEG concentrations typically found in fieldtype units designed to meet a 4-7 Ib/MMscfpipeline specification there is a 10-15Op difference between the Parrish and Worley equilibrium dewpoints. In the design of these units, theuncertainties in tray efficiency, TEG concentration and circulation rate far outweigh the differences in equilibrium data.However, for extremely low outlet water contents, the importance of the lean TEG concentration is far greater. It is in the region (outletdewpoint < _10 [_23C]) that the Parrish correlation is recommended.2. lEG-Hydrocarbon Equilibrium DataCoabsorption of natural gas components in TEGsolutions is a naturally occurring consequence ofthe dehydration of natural gas. In general, thesolubilities of low molecular weight paraffin hydrocarbons is small. Jou et al. 31 presents solubility data for methane, ethane and propane inpure TEG. Their data indicates the old field"rule of thumb" for gas solubility - 1 scf/U.S3 galTEG at 1000p and 1000 psia [7.5 std m 1m3TEG at 3SoC and 6900 kPa] to be pretty accurate. Solubilities of C02 and H2S , also investigated by Jou, are considerably higher than forparaffin hydrocarbons.

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However, the big uncertainty in gas dehydrtoday is the solubility of aromatic hydrocarin TEG. The solubilities of liquid aromatiTEG are well documented. In fact, TEG isto extract aromatics from paraffin hydrocarbThis data is not applicable when the aromare a dilute component in the vapor phaseral gas stream. There is virtually no data inopen literature for this system.Fitz and Hubbard32 presented a method ofmating the coabsorption of benzene in TEtypical contactor conditions using Henry'sThe correlation was developed by extrapolbenzene-DEG data using a group contribumodel. At typical glycol circulation ratesand Hubbard estimate that 5-20% of thezene in the gas may be absorbed in the TEGpending on the TEG circulation rate. Thisbeen confirmed informally by limited field dAdditional experimental data in this area iquired. The GPA and API have embarkedjoint project to study aromatic solubilitieTEG. It should be completed by mid to1991.SUMMARY AND CONCLUSIONSAlthough natural gas dehydration is amundane and well established process, it isential prior to the sale and/or processing ofural gas. Recent developments in the arephase equilibria, process modifications andronmental regulations have impacted the dand operation of dehydration systems.paper has summarized a few of the most imant developments and their effects on dehytion systems.

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SPE 21507 ROBERT A. HUBBARD 9

REFERENCES1. McKetta, J. J. and Wehe, A H., PetroleumRefiner (Hydrocarbon Processing), (August1958).2. McCarthy, E. L. et al., Trans. AIME, Vol. 189(1950), p. 241.3. Maddox, R. N. et al., "Estimating Water Contact of Sour Natural Gas Mixtures," Proceed-ings, Gas Conditioning Conference,University of Oklahoma (1988).

4. Campbell, J. M., Gas Conditioning and Pro-cessing, Vol. 1, The Basic Principles, 6th Edition (1988).5. Sharma, S. C., "EquilibriumWater Content ofGaseous Mixtures," Ph.D. Thesis, Univ. ofOklahoma (1969).6. Robinson, J. N. et al., "Estimation of theWater Content of Sour Natural Gases," SPE1 (August 1977).

7. GPA Research Report No. 45, Gas Processors Assoc., Tulsa, Ok (Dec 1980).8. Hammerschmidt, E. G., "Formation of GasHydrates in Natural Gas TransmissionLines," Ind. &Eng. Chem., 26,851 (1934).9. Deaton, W. M. and Frost, E. M., "Gas Hydrates and Their Relation to the Operationof Natural Gas Pipe lines," U.S.B.M. Mono-graph 8 (1946).

10. Davidson, D.W., "Clathrate Hydrates," inWater: A Comprehensive Treatise, Vol 2,Chptr 3, 115 (1973).11. Kobayashi, R., "Vapor liquid Equilibria inBinary Hydrocarbon-Water Systems," Ph.D.Thesis, Univ. of Mich., Ann Arbor, MI(1951).12. Carson, D. B. and Katz, D. L., "Natural GasHydrates," Trans. AIME, 146, 150 (1941).13. Campbell, M., op. cit.14. McLeod, H. O. and Campbell, J. M., "Natural Gas Hydrates at Pressures to 10,000psia," Trans. AIME, 222, 590 (1961).15. Parrish, W. R. and Prausnitz, J. M., "Dissociation of Gas Hydrates Formed by Gas Mix-

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tures," Ind.Eng.Chem. Process Des.Develop,Vol II No.1, 26 (1972).16. Van der Waals, J. H. and Platteeuw, J. C.,"Clathrate Solutions," Adv. Chem. Phys., Volll , 1 (1959).17. Sloan, E. D., "Hydrate Nucleation from Ice,"Proc. 68th GPA Convention, Phoenix(1990).18. Hammerschmidt, E. G., "Gas Hydrate Formations," GAS (May 1939), p. 30.19. Nielsen, R.B. and Bucklin, R.W., "Why notuse methanol for hydrate control?"Hyd.Proc. (April 1983), p. 71.20. GPA Research Report No. 92, 'The Effectof Ethylene Glycol or Methanol on HydrateFormation in Systems Containing Ethane,Propane, Carbon Dioxide, Hydrogen Sulfideor a Typical Gas Condensate," Gas Processors Assoc., Tulsa, OK (Sept. 1985).21. Maddox, R. N., private correspondence22. Anderson, F. E. and Prausnitz, J. M., "Inhi-bition of Gas Hydrates by Methanol,"

AIChE1, 32, 8, (August 1986), p. 1321.23. Wise,H., Puck, T.T. and Failey, C.F., "Studies in Vapor liquid Equilibria ll, The Binary System Triethylene Glycol-Water," 1

Phys. Chern. (1950), 54, 734.24. Porter, J.A and Reid, L.S., "Vapor-liquidEquilibrium Data on the System NaturalGas-Water-Triethylene Glycol at VariousTemperatures and Pressures," Trans. AIME(1950), 189, 235.25. Townsend, F. M., ''Vapor-Liquid Equilibrium Data for DEG and TEG-Water-Natural Gas System," Proceedings, GasConditioning Conference, University ofOklahoma, Norman, Okla. (1953).26. Scauzillo, F. R., "Equilibrium Ratios ofWater in the Water-Triethylene Glycol-Natural Gas System, 1 Pet. Tech. (July 1961),698.27. Worley, S., "Super Dehydration with Glycols," Proc., Gas Conditioning Conference,Univ. of Okla. (1967).

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10 RECENT DEVELOPMENTS IN GAS DEHYDRATION & HYDRATE INHIBITION SPE

28. Rosman, A, "Water Equilibrium in the Dehydration of Natural Gas with TriethyleneGlycol," Soc. Pet. Eng. 1 (Oct. 1973), 297.29. Herskowitz, M. and Gottlieb, M., ''Vaporliquid Equilibrium in Aqueous Solutions ofVarious Glycols and Poly (Ethylene) Gly

cols, 1, Triethylene Glycol," 1 Chern. Eng." Data (1984),29, 173.30. Parrish, W.R., Won, KW. and Baltatu,M.E., "Phase Behavior of the TriethyleneGlycol-Water System and Dehydration/Regeneration Design for Extremely Low DewPoint Requirements," Proceedings, Gas Processors Association 65th Annual Meeting,San Antonio (1986).31. Jou, F.Y. et al., "Vapor-liquid Equilibria forAcid Gases and Lower Alkanes in

Triethylene Glycol," Dept. of CbB., U. ofAlberta, Edmonton.32. Fitz, C. W. and Hubbard, R. A, "QuickManual Calculation Estimates Amount ofBenzene Absorbed in Glycol Dehydrator,"

O&GJ (Nov. 23, 1987), p. 72.

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SPE 2150

Figure 1Water Content ofHydrocarbon Gas

1.850 '0000

80006000

Correctionfor Salinity 4000

2000

400

100

800

eo

600

60

'000

I

Total Solids in Brine. %

.. ' 1.00 c r "T"T . . , . , . . " r r r - r rTTT"T"T" " ' " " "ni 0.98 ~ t t ~ ; E ~ a : E t n E ~ : Ei 0.96 ! + + + - H + - I ~ l + H - f + + + - H - HlJ..,lJ..o i 0 0.94 ~ m : t t 1 t 1 ~ ~ ~ : : t : t : ~1 0.92 ~ t t t t l : t l : t t : t ~ ~ ~ ~I 1-U 0.900L . L . J . . . . L - L . . J . l . . . . L . . J u . . . . 1 . . . 2 ~ . L . J . . . L . I . 3 . . L - L . . . . L . . J U 4

60 0800

20e

'000

Warning: Dashed lines are' - " " " 'meta-stable equilibrium.Actual equilibrium is lower ll1water con tent . Ang le i s aJ::1= ...Jfunction of composition. ~ lla

1 : ~ I I ! ~ ~ ! I ~ ! I I I . l ~ I I ~ it~ wcr

40 H--+- - t -+- f - - f r - " r -no- - i r - 0 , 40H-+-+-l--+,. . ,L-f-+,l--+-+/7 'W-lf''7f-H1Yl~ i Y l l 7 ' J ~ $ 4 - + + - H + + - i I - + - H ' + + + + t - H

..wCo.....oj"0c:..!I-o'"'iiU>..Cl

20

'a

2

' - 60 -2 0 a 20

Position of this lineis a function of gascomposition. 'a8

2

Source: GPSA Data Book, 10th Edition, 1987.273

7/27/2019 00021507 - Gas Dehydration

12/14

-10.0

Figure 2Water Content @ 650 psia of Natural Gas in Equilibriumwith Metastable Liquid and Hydrate Solid

.,V "

Metastable :::::Jl"""V ...........V

V .....-./ ~ V1/ k::::: Hydrate.....-

~v. /

V

...0III:::: 1.0a~zWI -Z00a:w 0.1!;(3=

0.0170 -60 -so -40 30 20

TEMPERATURE, of10 o 10

FIGURE3QUALITATIVEEXAMPLEOF SUBCOOLINGREQUIRED FORHYDRATE CRYSTALIZATION

h ~ r a . . ! . e d i s ~ ~ ~ n __pressure

II_ IIII

III~ subcooling requiredI to percipitateI hydrate crystals

TEMPERATURE

274

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13/14

SfiE 2 1507

Figure 4Comparison of Experimental Hydrate Formation Conditions in thePresence ofEG (RR92) with Hammerschmidt Equation

1/)i i /.1f. ~ ~ ~ . t.

/. //!- /".... " /.'i ' t.'..:., ,t /'./' " t..... l, ' , ' I V, I

Ii

4000

2000ttlUiCoui 1000

800~ 600wa:a. 400

200

100-20 -10 o 10 20 30 40 50TEMPERATURE, of

60 70

-. - Hammerschmidt, 50% EG- - Hammerschmidt, 25% EG." .. Experimental, 50% EG- " - Experimental, 25% EG_ Experimental, 0% EG

80

Figure 5Comparison of Experimental Hydrate Formation Conditions in the PresenceofMeOH (RR92) with Hammerscmidt and Nielson and Bucklin Equations.

Nielsen & Bucklin, 50% MeOH_ Nielsen & Bucklin, 25% MeOH

Hammerschmidt, 50% MeOHHammerschmidt, 25% MeOH

.".. Experimental, 50% MeOHExperimental, 25% MeOHExperimental, 0% MeoH80

,; III . , .' }.I ......... .V // .. ,, ..... ,7, .. .' / /. ." ,." V......

i l: .1 Vi o.f iM1'" ",,' iIt80-40 -30 -20 -10 0 10 20 30 40 50 60 70TEMPERATURE, of

320

~ 2 0 0

160

4800

ttl 1600"iiiCo

a: BOO~ 640ffj 480a:a.

275

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14/14

seE 2150 1.

Figure 6Equilibrium Water DewpointswithVarious Concentrations of TEG(Nominal range" 14.7psia to 1500 psia) vo /95

V / /".....V V / /"0 V v V/ /' "....-/ / V V V

/ V ....-V .....V /'/ V / .......... V ./ 99.00 / V VV V V/ / '"V / v:.V / l/ ./ 99.5/ V ' / v V " , , / V./ . / 99.7/ V l/: /" /'V V ""V V 99.8./0 ..... ~ V / v , / V ", V/ . / 99.'V V , / ."...-

V. /

./ ..,......V...- 99.950 ,/'" V V / / 99.97V . / . / , / ..,...... V V/ , / V V / ", /. :::...-"'" " "" , /, / , / ,, / / v ~ :/' ",. /

./ / , / / ......::r;/ " . ,, / ./ """' , /V v '/ ",. / V'::/ ' Y. " .,."...- V ~v/ .

20

60

100

-2

-4

-6 0

-6 0

40 60 '0 100 120 140 160 180Conlact temperature. OF

Source: GPSA Data Book, 101h Edition, 1987.

Figure 7EquilibriumWater Dewpoints Above TEG Solutions vs. TemperatureTEG Cone.,

wt%100

80

II . 600' i 40'0CoCIl 20E.:! 0g'SC'" -20w

-40

-60

-8070 80 90 100 110 120 130 140

Temperature, OF