Acid-sour Gas Management in the Petroleum Industry

8/12/2019 Acid-sour Gas Management in the Petroleum Industry

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2 ACID/SOURGAS MANAGEMENTN THE PETROlEUM NDUSTRY SPE 49522in the injection gas is considerably greater than dlisvalue. In other instances, the H2S content in the acidgas streams are seen o be lower as well (in die range of100/0 nd the remaining component is COJ.Injection of Compressed Acid Gas into the PorousFormation. Sour natural gases are sweetened byremoving H2S and CO2 by absorption with aregenerative solvent in an amine plant. The acid gasmixture of H2S, CO2, and a small amount of lighthydrocarbons leaves he sweetening unit saturatedwithwater at the amine still conditions of low pressure andhigh temperature. The gas mixture is then compressedin 3 to 4 stages. After each stage, the gas mixture iscooled, without entering the two-phase region.Condensed water is removed after each stage. Afterthe last stage, he mixture travels down the pipeline intothe disposal well. Ideally at the fmal compressordischarge pressure, the mixture will be supercritical.Further cooling in the pipeline will increase he densitywithout a phase change, increasing the hydrostatic headof fluid in the well and reducing the required injectionpressure. The operator must ensure d1at the mixturedoes not cool below its water saturation temperature,especially in the hydrate region, to avoid corrosion andhydrate plugging of the pipeline and wellbore.

Corrosion and hydrates may occur when the gas issaturated with water. Due to the safety hazardassociated with acid gas equipment failure, mostinjection schemes currently include dehydrationfacilities to ensure the acid gas is undersaturatedthroughout the system. Unfortunately, dehydrationfacilities and stainless steel comprise a major portion ofthe capital cost of re-injection facilities. Methanolinjection is an option to combat corrosion and hydratefonnation, but can significantly increase operatingexpenses.Although there is little experimental data on acidgas mixture, the solubility of water in pure H2S andCO2 ead to some interesting hypotheses. The ability ofthe pure c0mp01Dlds o hold water in the vapor phasedecreases as the pressure increases up to about 3000kPa (400 psi) for H2S and 6000 kPa (900 psi) for CO2.At higher pressures dte water holding capacity of thegases increases, corresponding to a higher waterabsorption capacity in dte liquid phase or dense phasecompared to the vapor phase. In both cases, naeasingthe temperature allows more water to be absorbed in

water in die system and reduce corrosion and hydrateconcerns. Dehydration facilities comprise a majorportion of die capital cost of re-injection facilities.Alternatively, stainless steel materials and med1anolinjection are used to combat corrosion and hydrateformation conditions. However, diis alternative is alsoexpensive and poses significant operating problems. Analternative and cost-effective approach would be tokeep die water in die vapor phase throughout theinjection circuit, eliminating die need to dehydrate.

To design an optimized injection strategy widioutdehydrating the acid gas, detennination ofthermodynamic properties (i.e. water content,dewpoint, bubble point, and hydrate points) of die acidgas is necessary. The system may also be designed toinject die mixture as a dense phase, above die criticalpoint, reducing die required injection pressure andhorsepower requirement due to die hydrostatic head ofdie colwnn of fluid in die injection wellbore. Thehydrate curve information will ensure diat the systemnever enters die hydrate region, reducing die risk ofpipeline plugging.An alternative approach is to solubilize die acid gasin produced or source water in a high pressurecontacting tower on the surface, followed bysubsequent injection of die sour water.s Anunderstanding of die solubility of die injected gas or in-situ water phase is essential in order to quantify diespeed of migration of die injected gas (in a directinjection scheme) and to design the contactingapparatus and determine volumes of water required toeffect disposal in a sour water disposal scenario.

Anodier approach is to solubilize acid gas nto lighthydrocarbon solvent (taking advantage of highsolubility of acid gas into light hydrocarbon solvent),and subsequently, use die light hydrocarbon solventcontaining acid gas into die depleted hydrocarbonreservoir as a miscible flood enhanced oil recovery(EOR) tedmique.Experimental tests and results of various processesare discussed n this paper. In addition, advantagesanddisadvantages of all diese options are also discussed.Characteristics of Acid Gas StreamsA summary of basic characteristics of acid gascomponents are summarized in Table 1.6.7As seen inthe table, bodt gases have diatomic structme andexhibit high propensity for solubilizing in both aqueous


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compression inlet conditions of2.8 MPa (400 psi) and24C (75F). A mixture of 100/0H2S and 900/. CO2was prepared. A small amount of CH. was added andthe exact composition verified with dte OC. Themixture was saturated widt water at 2.8 MPa (400 psi)and 24 C (75F). After several hours of rocking, dteaverage water content was detennined.

Several isodtenns were obtained to establish thephase envelope. The cell temperature was set andallowed several hours to equilibrate. The cell mercuryvolume was increased ncrementally, resulting in 15-30psi pressure steps. Transient and stabilized phasebehavior was observed and recorded. The change inmercury volume was recorded as a function ofpressure. At pressures close to dte dew and bubblepoints, dte volume/pressure increment was reduced. Bytaking a series of data points immediately above andbelow the appearance and disappearance of the two-phase region, the dew and bubble points wereestablished.

Isobaric cooling experiments were perfonned toestablish the hydrate fonnation conditions for this acidgas/water mixture. The oven temperature was raised to50C (122 oF) and dte gas was pressurized to between9000 kPa (1305 psia) and 17700 kPa (2567 psia) andallowed to stabilize. Since the gas was saturated widtwater at 2800 kPa (400 psia) and 24 C (75 oF) and dtewater content was not changed as the temperature andpressure were raised, the gas was undersaturated at dteconditions of high temperature and pressure. Thetemperature was dten reduced in 1.6 C (3 OF) stepsevery 30 to 45 minutes until a hydrate was visuallyobserved in dte cell.The hydrate fonnation temperature measured n thismanner differs from dte traditional hydrate temperatureobtained by cooling gas in contact widt a liquid waterphase. When liquid water is present, hydrate fonnationis predicted to occur at elevated temperatures in dteorder of 20C (68F) at 9000 kPa (1305 psia). Whendte gas is not in contact widt a water phase and isundersatw'ated, hydrates cannot fonD until dtetemperature drops sufficiently dlat dte gas can nolonger bold all the water in solution and wfreewwater isavailable for dte fonnation of hydrates. Hydrates fonDpreferentially to a liquid water phase, since dte gas isalready below its satmated hYdratetem perature at theseconditions.

Res lts, observations and discussion. As recorded

bubbles appearedduring a volume/pressure change andwhile the system was stabilizing, but upon reachingequilibrium, the system was single phase at allpressures.

At 37.5C (99.5 oF) and 8253 kPa (1197 psia), thecritical point was observed. At all other temperaturesthe contents of the cell were clear and colorless in thevapor, liquid and two-phase regions. In the criticalregion, a small change in pressure (3-5 psi) resulted inthe entire cell contents becoming a murky, grey cloudand then stabilizing out into a variety of shades ofyellow. Above 8303 kPa (1205 psia) the contents weresingle phase, clear and colorless. At about 8274 kPa(1200 psia), the see-through single phase took on aslightly yellow tint. At the critical point of 8253 kPa(1197 psia), two phases appeared with an indistinctthick yellow interface, a darker yellow color at d1ebottom of the cell and a lighter yellow color on top. At8212 kPa (1191 psia) the bottom half of the cell was adistinct dark orange liquid and the top half a colorlessvapor. At 8198 kPa (1189 psia) the liquid phase fadedto yellow and below 7957 kPa (1154 psia) the cellcontents were again a colorless single phase.

In Figure 2, the calculated equation of state phaseenvelope is plotted along with the experimental data.The widths of the two phase envelopes are similar, butthe calculated envelope falls below and to the left ofthe experimental data. The calculated critical pointoccurs at 34.9 C and 7633 kPa (94.8 of, 1107 psia),2.6C and 620 kPa below the experimentallydetermined critical point of 37.5C and 8253 kPa(99.5F, 1197 psia). The deviations between actualand calculated phase behavior emphasize theimportance of obtaining an experimental data set foracid gas mixtures. The equation of state was regressedto fit d1ephasebehaviour data obtained experimentally.The regressed curves and critical point match themeasured data within the experimental error. Themodified equation of state allows some extrapolation todifferent conditions, but experimental verification willbe necessary until more data becomes available and ageneral regression is completed.The Sa11D'atedater content of the gas mixtW Cat2860 kPa and 24C (415 psia and 75F) over foursamples was measured o be 0.6 mole percent or 270 Ibwater/MMSCF. This value is over three times d1evalue that analysis of accepted pure component dataand equation of state calculations predict. The


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SPE 49522 A.KM. JAMALUDOIN. .B. BENNION.F B. THOMAS.MA CLARK 537.5C between compression stages. The fluid is inthe supercritical, dense phase above 8253 kPa andabove 37.5C.

The hydrate formation temperature is below thetraditional hydrate temperature since the gas is not incontact with a liquid water phase. With undersaturatedgas, hydrate fonnation is expected to coincide with dtewater saturation temperature. In this study, hydrateswere observed at temperatures above the expectedwater saturation temperature of the gas. At 9000 kPa(1305 psia) and 17700 kPa (2567 psia) predictionsbased on pure component water saturation data ndicatethe gas will be saturated at approximately -9C (15F)and -18C (0 oF), while hydrates were observed at -2 C(28F) and 8C (46F). The difference can beattributed either to experimental error or theinaccuracies inherent in predicting mixture saturationtemperatures rom pure component data. In either case,since the observed hydrates occurred at highertemperatures than expected, a conservative designwould not require dehydration of the gas unless thetemperature in the pipeline or wellbore dropped belowthe observed hydrate formation temperature.Disposal of Acid Gas with DisposableFonnation WaterSour water injection has advantages and disadvantagesin comparison to direct injection. The technique resultsin better containment of the sour gas as it is dissolvedin the injected aqueous phase and, excepting diffusiveforces which act very slowly in porous media, the sourwattt moves only as the injected phase spreads nto thereservoir. This also lessenssafety concerns with respectto rate of release and volume of release in the event ofblowout of a sour disposal well. Compression costs arereduced, as the effluent is pumped down the well as aliquid phase using conventional equipment (withappropriate corrosion inhibition). Disadvantagesinclude concerns about corrosion in the surface andinjection equipment, hydrate in the contactingequipment, cost and safety of the surface contactingequipment, and the fact that the phase behaviour of thesour water must be precisely detem1med o ensure thatsour gas is not liberated from solution as temperatureincreases as the fluid is heated by contact with thefonnation. The water-contacting process also suffersfrom the fact that it is not a perfect method for removalof acid gases and preferentially tends to adsorb H2S

acid gas Sb'eam. This reduces the cost. volume and H2Scontent of the remaining residual gas whichsubsequentlywill be processed y more conventionalmeans.Solubility of acid gases n aqueoussolution is afunction of the following parameters:. Acid gas composition. Contacting pressure. Contacting temperature. Water salinitySolubility increases with increasing H2Sconcentration and increasing pressure (although

solubility generally levels out near the critical pressureof the mixture (about 7000-10000 kPa). Solubility isreduced by inaeasing temperature and increasingsalinity of the contacted water. Figure 4 provides anillustration of the solubility of pure carbon dioxide infresh and salt water at various pressures at 100C.There are virtually no published data on the solubilityof mixtures of acid gases n water. Table 2 provides asummary of some limited selected solubility dataavailable for different concentrations of acid gases atvarioustem perature and pressure contacting conditions.Detailed experimental solubility studies should beconducted prior to any acid gas injection study. Thiswill quantify the compatibility and expected solubilityof the target acid gas stream in the specific aqueousphase present in the reservoir or contemplated for co-injection.Problems may be associated with solubility ofhydrogen sulphide into water. Water solutionscontaining H2S are not stable and reaction withadsorbed oxygen can cause the precipitation ofelemental sulphur\) and turbidity. This may result inplugging of the injection zone by the suspended solidprecipitate. The turbidity can be reduced by filtration orstabilized with various inhibitors (ie. glycol), but bothtechniques may increase the cost of the injectionoperation significantly thus reducing the economicviability of d1esour water injection operation.Solubilize Acid Gas into Light HydrocarbonSolvent and Inject the Solvent Containing Acid GasComponent into tbe Depleted Reservoir as aMiscible Flood Enhanced Oil Recovery (EOR)Technique. Rich acid gases exhibit extreme solubilityin liquid hydrocarbons at elevated pressures (gas-oilratios of acid gases n hydrocarbons. particularly light


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condensate reservoirs or some gas reservoirs whichhave been created by gas migration over geologicaltime into previously oil bearing strata. As the liquidsaturation increases n value, it still remains below theirreducible value and hence is not mobilized, butexpands and occludes space previously available forgas to be injected. The end result can be a significantreduction in gasphase njectivity if the configuration ofthe gas phase relative penneability curve is very steepat low liquid saturation values. Figure 6 provides anillustration of this phenomena.This problem is very difficult to diagnose withoutdirect field or lab testing. Conventional gas-liquidrelative penneability curves can provide some insight,but the parameters and configuration of nonnal gas-liquid relative penneability curves are generallysignificantly altered when considering an acid gas-oilor acid gas-water system. Dissolution of the acid gas nthe liquid phase significantly reduces its viscosity (byan order of magnitude or more for some hydrocarbonliquid systems) and also can substantially reduceinterfacial tension between the gas and liquid phases.Potential Side Benefits. Acid gas re-injection mayhave potential side benefits in addition to the directdisposal of unwanted sour gas. Some of these factorshave been alluded to previously, but will now bediscussed in greater detail. They include:Potential stimulative nature caused by carbonatedissolution. In the absence of adverse precipitationeffects and dissolution induced fmes mobilization andplugging, long-term acid injection may actuallyimprove injectivity in some disposal wells due to lowpH induced dissolution effects.Desiccation. In most direct acid injection projects,the injected acid gas will have been dehydrated tominimize hydrate problems at surface. Due to higherdownhole temperatures, hydrate formation willl&elynot be problematic, but the dry nature of the injectiongas may result in a gradual desiccation of the trappedirreducible or connate water saturation from the regionadjacent to the injection zone. This is analogous to aphenomenon which often occurs during injection ofconventional dry gas into gas storage reservoirs. Thereduction in initial water saturation can cause anincrease in injectivity due to a lessening of adverserelative permeability effects associated with thepresence of the initial water saturation in the porous

saturation, depleted gas reservoirs containing an initialirreducible or sub-irreducible oil saturation, anddepleted retrograde condensategas zones containing atrapped irreducible or sub-irreducible criticalcondensate saturation. Two potential concerns arisewith respect to the contact of these hydrocarbon liquidswith the acid gas as follows:Compatibility. Many oils may de-asphalt whencontacted with diatomic gases such as CO2 and H2S.The precipitation of granular solid asphaltenescan leadto plugging of the pore system and restricted injectivityin the near wellbore region. If injection into a zonecontaining liquid hydrocarbons is contemplated,detailed compatibility testing should be conductedbetween the live hydrocarbon liquid and the proposedinjection gas over the range of expected downholeinjection conditions to ensure that destabilization ofasphaltenes rom the liquid hydrocarbon phasedoes notoccur.Swelling. Due to the extremesolubility exhibitedby rich acid gases n most hydrocarbons a largeformation volume factor increase expansion of the sizeof the liquid hydrocarbon phase) occurs when the acidgas contacts the insitu oil. If pressure is sufficient, theacid gas may actually be miscible with the insitu crudewhich will result in miscible displacement of theresidual oil saturation away from the wellbore area,potentially creating an advantageousncrease n relativepermeability to the injected acid gas and an increase ininjectivity. In many situations, the composition of theacid gas, liquid hydrocarbon gravity and downholetemperature and pressure conditions are not conduciveto the establishment of miscibility. In this situation, aportion of the injection gas s absorbed nto the trappedliquid hydrocarbon phase, causing a large increase information volume factor of the oil. Figure 5 provides apressure-composition diagram for a typical insituretrograde condensate phasewith a molecular weight ofapproximately 110 when contacted with a 50%H2S/500/oCO2 acid gas stream at 10000 kPa and 60 C.It can be seen at the saturation point (ie. point wherethe saturation pressure of the liquid is equivalent to theinjection pressure of 12000 kPa representing themaximum degree of swelling expected to occur) that anincrease in condensate volume of over 27% occurs dueto solubility effects.If the expanded oil saturation is already at the


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ReferencesWichert,E. andT. Royan, Sulphur DisposalbyAcid Gas Injection, SPE 35585, GasTechnology Conference, Calgary, Alberta,Canada, May 1996.

saturation removal, depending on the location of the re-precipitation within the pore system.limited Or Fun Miscibility with In-situ Oil Mostacid gas streams represent excellent miscible injectionsolvents (from a phase behaviour point of view) andvery low or zero interfacial tension can be obtainedwith these gases with many oils at relatively lowpressures. This makes these gases potential EORinjectant candidates for the miscible displacement ofoils (which are generally in and of themselves alreadysour). Due to the supercritical nature of the gas, actualvolume available for injection is usually too small to bean effective consideration for voidage replacement foran EOR process. Situations do exist. however, wherethe rich acid gas, extracted from produced solution gasfrom a large oil reservoir or directly from a sour gasreservoir, could be used o miscibly inject into adjacentsmaller oil pools or isolated zones of the source oilpool. Detailed lab and numerical studies would berequired in this situation to confinn miscibility with theinsitu crude, pressure required to maintain low1FT/miscibility and potential compatibility concernswith the gas-crude system and injectivity issues asdiscussed previously. Contingency plans for prematureultra-sour gasbreakthrough at a producing well are alsoa necessity in this situation.

1.

Keushnig,H., Hydrogen Sulfide - If You Don'tLike It, Put It Back, Journal of CanadianPetroleum Technology, 34(6), June 1995, 18-20.

2.

Longworth,H.L., G.C. Dunn andM.Semchuck,UndergroundDisposal of Acid Gas n Alberta,Canada: Regulatory Concerns and CaseHistories, SPE 35584, Gas TechnologyConference, Calgary, Alberta, Canada, May1996.

3.

Clark, M.A., W.Y. Svrcek, W.D. Monnery,A.K.M. Jarnaluddin. D.B. Bennion, F.B.Thomas, E. Wichert, A. E. Reed, and D.J.,Johnson, Designing and Optimized InjectionStrategy for Acid Gas Disposal widtoutDehydration, paper presented at dte 11mAnnual Convention of dte Gas ProcessorsAssociation,Dallas, Texas,March 16-18,1998.

4.

Duckworth, G.L., D. Kopperson, S. Home, G.Kohn, D. Romansky, and C. ChaD, Dispoal ofAcid Gases with Oilfield Produced Water,paperpresented t the 7~ Annual Conventionof the Gas Processors Association, Dallas,Texas,March 16-18,1998.

5.SummaryAcid gas or water injection has proven to be a viabletechnology for the disposal of large volumes of wasteacid gas. For compressed acid gas injection, either asa disposal or miscible solvent, the operating companymust avoid the two-phase region during compression.Water condensation and hydrate formation in the post-compression equipment must be prevented to ensure asafe, cost-effective operation. Experimental data on thewater content, density, hydrate and phase behavior ofacid gas mixtures is therefore necessary. In the case ofthe studied acid gas mixture of 9.90/0H2S, 89.5% CO2and 0.6% CR., dehydration is not required unless thetemperature drops below 8 C at 17700 kPa. The two-phase region will be avoided during compression bymaintaining the gas emperature above 37.5 C betweenstages.

AssociationSuppliersNatural Gas ProcessorsHandbook, Gas ProcessingOrganization,Tulsa, O.K., 1980.

6.Merck Chemical Index, Ill Edition. Merck &Co. Inc., Rahway, N.J., USA, 1983.7.Song,K. and R. Kobayashi, Water ContentofCO2 n Equilibrium with Liquid Water and/orHydrates , SPE Formation Evaluation,December1987,500-508.

8.

Selleck,F.T., L.T. Cam1ichaeland B.H. Sage,AcknowledgmentsThe authors would like to thank Union Pacific 9.


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8 ACID/SOURGAS MANAGEMENTN THE PETROLEUMNDUSTRY SPE 49522Carroll, J.J. and A.E. Mather, PhaseEquilibrium in die SystemWater-HydrogenSulfide: ExperimentalDetenn ination of die LL VLocus , Canadian Journal of ChemicalEngineering.,67, June, 1989, 468-470.

10.

Ng, H., D. Robinson and A. Leu, CriticalPhenomena n a Mixture of Methane,CarbonDioxide and Hydrogen Sulfide , Fluid PhaseEquilibria, 19, 1985,273-286.Huang. S.. A.D. Leu. H.J. Ng and D.B.Robinson. The Phase Behavior of twomixtures of Methane. Carbon Dioxide.Hydrogen Sulphide. and Water . Fluid PhaseEquilibria. 19. 1985. 21-32.

12.

Mussumeci,A., Computation n Gas HydrateFonnation SPE 21112, presented t die SPELatin America Petroleum EngineeringConference,Rio de Janeiro,Oct. 14-19,1990.

13.

Dodds, W.S. et aI, CO2 Solubility in Water ,Chern.Eng. Data Series1, 1956,p. 92.14.Munjal, P. and P B. Stuwart, Solubility ofCarbon Dioxide in Pure Water, SynfueticSeaWater and SynfueticSeaWater Concentrates t-5C to 25C and 10 to 45 ATM Pressure ,Journal of Chemical Engineering Data, 15,1970,67.

IS.

Simon, R. and D. Graue, GeneralizedCorrelations or PredictingSolubility, Swellingand Viscosity Behavior of CO2-Crude OilSystems , Journal of Petrolewn Technology,Ian 1965,p. 102.

16.


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Table 2: 10% Nominal D,S With \ .68/0 C. and CO.. Experimental Data

Dry Gas Composition:9.90/0 zS,89.5%, COz,0.6% CH.Wet Gas Com sition: 9.7% H 0


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Acid-sour Gas Management in the Petroleum Industry

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