Developing Low Sour Gas

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Developing Low Sour-Gas Reserves with Direct-Injection

Liquid Hydrogen Sulfide Scavengers

By J.G.R. Eylander, H.A. Holtman, Nederlandse Aardolie Maatschappij;T. Salma, M. Yuan, and J.R. Johnstone, Baker Petrolite

Baker Petrolite

The toxicity of hydrogen sulfide in hydrocarbon streams is well known in the industry and consider-able expense and efforts are expended annually to reduce hydrogen sulfide content to a safe level.In large production facilities, regenerative systems are typically installed for treating sour gasstreams. During the development stages of relatively small, low sour-gas fields at remote and nor-mally unmanned locations, regenerative systems are neither practical nor economical. In such fields,sour gas production is treated with non-regenerable scavenging processes.

In the development of its low-sourZechstein gas reserves in the Coevordenfield in the north-east region of TheNetherlands, the Nederlandse AardolieMaatschappij (a Shell operating unit, here-after referred to as NAM) decided to adoptcontinuous direct-injection of liquid scav-enging agents as the lowest overall costprocess having the least environmentalimpact and the highest energy efficiency.At the inception of the project, the operat-ing parameters controlling the scavengingefficiency using direct injection of liquidscavengers in this system were largelyunknown. Consequently, numerous field trials using different chemistries and different injection mechanics had to be carried out.

This article presents the results of thesefield trials, which ultimately led to a verysuccessful and profitable field developmentstrategy. A variety of very challengingoperational problems were encounteredand solved. Reference is made to injectionnozzle blockages, fouling of glycol gasdehydration systems, severe scaling prob-lems in production and downstream watertreatment/injection facilities, inadequatehydrogen sulfide removal efficiencies andHS&E-related issues. A better understand-ing has been gained of the fundamentalrelationships between operating parame-ters governing direct-injection processes

and associated chemical development andapplication methods. Communication andintegration of experience and knowledgebetween the operating unit and its chemi-cal supplier were key success factors in thisachievement, as was the endurance andcontinuing support of field operations staffin facilitating the resolution of difficultproblems.

IntroductionNAM’s Ten Arlo system (Fig. 1) producesgas from 32 satellite locations and four gastreatment/compression plants. The majori-ty of the fields in the system produce sweetgas from the Limburg reservoir. However,the system’s heavily compartmentalizedCoevorden field also contains gas accumu-lations in the Zechstein reservoir with H2Sconcentrations up to 300 ppm(v).Developing these accumulations wouldrequire extensive modifications to existing(sweet) gas production/treatment facilitiesto ensure safe operations and the preven-tion of H2S emissions. The produciblereserves were small, yet economicallyattractive. However, due to their geo-graphical scatter, a pipeline grid connect-ing these low sour-gas accumulations to anexisting nearby plant utilizing a regenera-tive solvent process for gas sweetening wasfound to be economically unfeasible. In-field desulferisation with, for example, a

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Fig. 1 Ten Arlo gas gathering system Fig. 2 Reaction pathway of Triazine and H2S

solid-bed adsorption process, was found tobe technically feasible, but the requiredcapital investment and perceived life-cyclecosts could not be justified.

To allow production of the low sourgas without violating the Ten Arlo sales gas specification for maximum allowableH2S concentration (5 mg/Nm3 or 3 ppm(v)),NAM evaluated in-field desulferisation uti-lizing a commercially attractive alternativetechnology.

Direct-Injection H2S ScavengingThe injection of chemicals into producedgas streams to remove H2S is a fairly oldindustry practice. Formaldehyde has beenone of the most frequently used materials,

but its use is strongly discouraged owing tothe reported carcinogenic properties.Chemistries such as sodium chlorite, causticsoda, glyoxal and others have been testedas well. These chemistries often havesevere disadvantages associated with them,ranging from handling and operationalproblems as a result of high reactivity toslow reaction rates.

The development of a non-regenerableclass of chemistry, commonly referred to astriazines, was disclosed in 1990. The term‘triazines’ is used for a group of com-pounds, which in reality, are substitutedhexa-hydro triazines. In this article, theterms ‘triazine’ and ‘hexa-hydrotriazine’will be used interchangeably. A generalrepresentation of a substituted hexa-hydrotriazine is given in Fig. 2, in which R1 to R6may be arbitrary hydrocarbon groups. Twowell-known triazine forms are disclosed inpatents1,2, in which R1, R2 and R3 areethanol or methyl groups, respectively, andR4, R5 and R6 are hydrogen. The productsare produced on a technical scale by react-ing either monoethanolamine (MEA) or atrimethylamine (TMA) with formaldehyde.

The actual reaction mechanisms of tri-azine compounds with H2S are not wellunderstood. The reaction is complex andproduces multiple reaction products.However, repeated laboratory analysis ofspent MEA triazine using NMR C13 spec-troscopy has established that H2S reactsirreversibly with MEA triazine with the S-atom being built into the ring structure,forming primarily two sulfur containingproducts – thiazine and dithiazine. In thereaction of MEA triazine with H2S, the sul-fur atoms are in the S2- oxidation state sothat solid elemental sulfur does not formand the reaction products are liquid.

Depending upon treatment rates, thereaction also releases either one or twomolecules of water-soluble alkanolaminemolecules: R-NH2. Because at least one Rgroup is retained in each product, the pri-mary products of the reaction of MEA tri-azine with H2S are low volatility liquidsthat are soluble in water (Fig. 2).

First Field ExperiencesA first field trial was carried out in 1995 atthe Coevorden-24 location utilizing a 1,3,5trimethyl-hexahydro-1, 3,5 triazine (prod-

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Baker PetroliteDeveloping Low Sour-Gas Reserves with Direct-InjectionLiquid Hydrogen Sulfide Scavengers

Fig. 3 Simplified set-up for field trial with Product A

Table 1 Fate of unreacted Triazine (Product A) and reaction products

uct A from supplier A), with injectionupstream of the glycol dehydration unit(Fig. 3). During the trial, gas productionoriginated primarily from two wells, withthe gas containing 24 and 45 ppm(v) H2Srespectively. Injection took place withoutthe use of an atomizer and at a dosagerate of approximately 6 L/kg H2S. As aresult of the injection, the H2S concentra-tion in the location’s export gas decreasedto well below the 5 mg/Nm3 limit.However, it was found that 40% by weightof the chemical did not react and ended upin the produced water phase. Not only didthis result in a potential water disposalproblem (owing to prevailing legislation),an unusual accumulation of solids wasencountered in the glycol system. The sub-sequently required change-out of the wetglycol filters resulted in unacceptableamine-type emissions spreading wellbeyond the location. Furthermore, thefunctioning of the in-line H2S analyzer (ofthe type utilizing a lead acetate tape) wasdisrupted.

Given the disappointing product yield(i.e., percent reduction in H2S) and theencountered operational problems, thedecision was taken to repeat the trial witha more concentrated version of the sametriazine. Initially, this product was injecteddownstream of the glycol dehydration unit

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Fig. 4 Simplified set-up for field trial with Product B

Table 2. Test Results with Product B

directly into the location’s export gas flow-line with the aid of an atomization nozzleat a dosage rate of approximately 4 L/kgH2S. Repeated blockages of the nozzlequickly resulted in its removal and the trialwas continued without it. Emphasis wasplaced on determining the product yieldand substantiation of the manufacturer’sclaim that reaction products would prefer-entially dissolve in the co-produced con-densate. The injection of the moreconcentrated product in the pipeline-wetexport gas stream rapidly reduced the H2Slevel to well below the contractual limit,with an H2S reduction of approximately97%. This represented a major improve-ment with respect to the first trial. As illus-trated in Table 1, both unreacted andreaction products were preferentially solu-ble in the produced water phase. The pres-ence of unspent and reacted scavenger inthe water necessitated permit applicationfor the installation and use of permanentinjection facilities on the location, whichwere installed in 1996. The chemical costassociated with the subsequent continuousH2S scavenging treatment of the exportgas stream amounted to approximatelyUS$30 per kg H2S.

Field Development ProgressionSeveral problem areas developed over timewith the chemical scavenging applicationas described above. Ten Arlo’s central gastreatment plant was confronted withincreasing pH levels in the glycol dehydra-tion system and amine emissions from ves-sels and drain pits, which were traced tothe scavenger application on theCoevorden-24 location.

Development of low sour gas accumu-lations at certain satellite locations lackinggas drying facilities was not feasible withthis scavenger application, not onlybecause transport lines did not meet theNACE specification for sour service but alsochemical costs would quickly become pro-hibitive. By 1997, the requirement for H2Sscavenging at the wellhead, driven by eco-nomics of the operation, combined withincreasing operator complaints aboutamine emissions, triggered field testing ofan alternative H2S scavenger consisting of1,3,5-tri (2 hydroxyethyl)-hexahydro-1,3,5-triazine (product B from supplier B). To dis-tinguish between the tests, three principalinjection regimes were tested as depictedin Fig. 4, without the use of atomizationnozzles. Results are given in Table 2.

Test A: Wet Gas Injection Regime, ModerateResidence TimeScavenging of H2S from 40 ppm(v) to therequired <3 ppm(v) required a scavengerdosage of approximately 10 L/kg H2S. Inorder to establish whether the H2S isindeed removed via the produced waterphase, a sulfur balance was made on thewater, condensate and gas phases. Duringthe test period, the sulfide concentration inthe produced water phase is seen toincrease and the sulfur balance (gas to liq-uid) climbs from an initial 44% to an 85%fit at the end of the test. The slow estab-lishment of equilibrium is explained by the inability to fully drain produced waterfrom the test separator prior to test execution.

During the test, the pH of the pro-duced water increased from an initial 5.6to 7.4 as the scavenger dosage increased.Massive overdosing of the scavenger raisedthe pH to 7.6. Throughout the test periodand even for a prolonged period there-after, no solids or scale formation was

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Baker PetroliteDeveloping Low Sour-Gas Reserves with Direct-InjectionLiquid Hydrogen Sulfide Scavengers

Fig. 5 H2S production profile of Coevorden-26 at Q = 100,000 Nm3/day

observed in the sampled fluids. However,produced water samples developed a yel-lowish color over time.

Test B: Wet Gas Injection Regime, ShortResidence TimeDecreasing the contact time between thescavenger and gas had a negative impacton the consumption of the product. Giventhe short duration of the test, no otherconclusion from this observation wasdrawn other than that it could possiblysupport an observation from other work 3

that the chemical injection rate has aneffect on the mass transfer of the chemical.

Test C: Dry Gas Injection Regime, LongResidence TimeIn this regime, we expected the scavengerto scavenge H2S from the dry gas, albeitinefficiently, with the reaction productsfalling out as solids in the absence ofwater. In this test, injection of the scav-enger in the dry gas stream downstream ofthe glycol dehydration system had nonoticeable effect on the H2S concentrationin the gas. This confirmed the earlier obser-vation that the scavenging reaction takesplace in the produced water phase. Theproduct’s manufacturer claimed that a min-imum required water content of 2 L/millionNm3 of gas was needed.

One of the objectives of the above testswas to prove that neither the chemical norits reaction products would cause anyadverse effects on water-condensate sepa-ration/quality and on the performance ofthe glycol dehydration system. No sucheffects were observed, but the relativelyshort test period could not provide conclu-sive evidence. From the test results, it wasconcluded that the scavenger was veryeffective at removing small quantities ofH2S from wet/saturated gas streams. If suf-ficient contact time was provided for therequired dosage of 10L/kg H2S, while a fac-tor 2.5 higher than that required for theexport gas scavenger, still provided areduction in chemical costs to approximate-ly US$ 10 per kg H2S. Given the positivetrial outcome, permanent injection facili-ties for product C were installed on thelocation’s main Header, while retaining thescavenger (product B) injection into theexport gas stream as back-up facility. Togain confidence that product C could also

be used on satellite locations by direct-injection at the wellhead, a more rigorousfield trial was designed that was alsoaimed at optimizing the treatment toachieve further cost reductions.

Extended Field TestingWell Coevorden-26 on the Coevorden-24location was selected for this field trial.This well is completed on both the (sweetgas producing) Limburg reservoir and the(low sour gas producing) Zechstein reser-voir. The pressure balance quickly favors(fractured carbonate) Zechstein productionafter the well is opened up to the extentthat steady state gas production with anH2S concentration increasing to approxi-mately 130 ppm(v) can be maintained for aperiod of about 10 days (Fig. 5). After thistime, the on-set of liquid loading necessi-tates well shut-in for several weeks toachieve pressure build-up.

In early 1998, the well was connectedto the test header (Fig. 4), with the injec-tion point (without atomization nozzle) asper Test A of the previous field trial.Injection of product C commenced simulta-

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Fig. 6 Sludge formation in flowline

Fig. 7 Results of first field trial with product SX 2656

neously with gas production, with the scav-enger injection rate set at the maximumexpected H2S level at the recommendeddosage of 10 L/kg H2S. The implied over-injection of the chemical was intended.During the trial period, the H2S scavengingperformance matched that of the first trial,yielding H2S reduction in excess of 99%.However, a gradual increase in the pres-sure drop across the flowline connectingthe well to the test header from an initial(normal) 2 bar to 8 bar was also observed.Subsequent internal inspection of the flow-line revealed that massive calcium carbon-ate scaling had occurred at and severalmeters downstream of the injection point.Following flowline clean-up throughacidization, a repeat trial was carried out,this time utilizing an atomization nozzleand preventing over-injection by tailoringthe scavenger injection rate to the actuallyproduced H2S concentration. Although thisreduced scale deposition to a certainextent, the net results were far from satisfactory.

Given the potential threat to theCoevorden field development plans, amajor effort was undertaken in conjunc-tion with the chemical supplier to solve thescaling problem. An experimental scav-enger was developed (product D from sup-plier B), in which product C was blendedwith a phosphonate-type scale dispersant.Late 1998 through 1999, a prolonged peri-

od of often-problematic field-testing fol-lowed utilizing this experimental product.The following observations were madeduring this period:

◗The experimental product appeared tobe effective in mitigating the deposi-tion of calcium carbonate scale.However, the chemistry employed informulating the product resulted inexcessive formation of a very viscousfoam, disrupting flow and liquid-levelcontrol systems and carrying the risk ofspillover into the glycol dehydrationfacilities.

◗To counteract foam formation, a sili-cone polymer emulsion was mixed intothe scavenger/scale dispersant blend.The resulting mixture appeared to beinherently unstable, requiring continu-ous mixing on site to avoid phase sepa-ration. Even with continuous mixing, itproved to be impossible to achieve ahomogeneous mixture and foam sup-pression was only partially achieved. Inaddition, a 50% reduction in the prod-uct performance in terms of liters ofproduct required per unit mass ofhydrogen sulfide removed was experi-enced.

◗Sludge formation occurred in the flow-line (Fig. 6), in the test separator andin downstream water/condensate stor-age facilities to the extent that itbecame unacceptable.

Irrespective of the encountered prob-lems, it was observed that the scavengerinjection rate had an effect on the productyield, but contrary to published resultsfrom earlier work3, no clear pattern couldbe established. Factors complicating theresulting interpretation are that a) lower-ing of the flowing tubing head pressureresults in higher linear gas velocities in theflowline, and b) the concomitant increasein the hydrostatic head in the well resultsin higher water-gas ratios. The dilutionresulting from the latter could alter thestoichiometry of the reaction between thetriazine and H2S such that the triazinecould possibly react with more H2S (on amolar basis) than in the (relative) absenceof dilution effects.

During the various trials, in going from

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Baker PetroliteDeveloping Low Sour-Gas Reserves with Direct-InjectionLiquid Hydrogen Sulfide Scavengers

Fig. 8. Influence of linear gas velocity

Fig. 9 Calcium Carbonate scale in flowline

higher to lower linear gas velocities, thenet reduction in H2S was seen to decreaseat first, but after passing through a mini-mum, a higher reduction in H2S wasobserved again. This would seem to indi-cate higher scavenger injection raterequirements at lower linear gas velocities,when there is less water production. Thesignificance of these observations couldonly be ascertained after a solution wasfound for the encountered problems. Itwas conceded at the time by the incum-bent chemical supplier that such a solutioncould not be made available in the timeremaining for the required firming up offield development plans.

Further Product DevelopmentsThe field testing of hydrogen sulfide scav-engers carried out thus far had generateda number of very clear technical perfor-mance criteria for wet gas application.Claiming the successful development of acombined scavenger/scale inhibitor formu-lation, which could meet these criteria,Baker Petrolite was invited to participate infield testing of this product (SX 2656).

SX 2656 was developed specifically tominimize calcium carbonate scale forma-tion that would normally arise from using ahighly alkaline triazine scavenger in calci-um and/or high bicarbonate producedwater. Based on extensive laboratory eval-uation of various scale inhibitors, a propri-etary phosphonate scale inhibitor wasidentified as the most effective at combat-ing calcium carbonate scaling resultingfrom injection of triazine into a producedbrine. The laboratory experiments indicat-ed that a) addition of the chosen scaleinhibitor significantly reduced calcium car-bonate scaling tendency, b) it had noadverse effect on H2S scavenging efficiencyof the triazine, and c) it did not cause fluidfoaming. The result was the developmentof SX 2656 that contained an optimum per-centage of the chosen scale inhibitor.

The scale inhibitor is completely solublein high pH brines and it exhibits a high effi-ciency at inhibiting high pH induced scaleprecipitation. This is a nucleation inhibitor,i.e., it inhibits the nucleation of calciumcarbonate scale crystals, thus keeping thescaling ions in solution.

Next-Generation Field TestingFollowing flowline clean up throughacidization, field testing of SX 2656 wasinitiated on well Coevorden-26 in the samemanner as the preceding field test, i.e.,injection at the wellhead through an atomization nozzle. Injection at a dosageof 10 L/kg H2S (slightly higher than the supplier recommendation of 8 L/kg H2S)yielded an average H2S reduction of 70%.By increasing the dosage to approximately15 L/kg H2S, the reduction in H2S rose toapproximately 93% (against a stipulatedperformance criterion of >99%). Reducingthis dosage to lower levels was immediate-ly coupled with increasing residual H2S levels.

The influence of the linear gas velocityon the product yield is shown in Fig. 8,whereby the observed data have been fit-ted to a calculated trend utilizing Holt’stwo-parameter linear exponential smooth-ing method.4 The trend appears to indicatethe existence of a threshold limiting valueabove which the product yield is indepen-dent of the linear gas velocity; the injectionrate seems to have little influence. Duringthe test, no increase in the pressure dropacross the flowline was observed. However,a camera-run revealed the presence of athick layer of calcium carbonate scaleblocking the top half of the flowline (Fig. 9). The conclusion was that the flow-

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Fig. 10. Results of second field trial with (overdosing condition)

Fig. 11 Sludge layer and cauliflower-like deposits

line acidization preceding the test had only been partially effective.

It was decided to repeat the test aftercleaning the flowline through sequentialhigh-pressure water jetting and acidiza-tion, followed by a camera-run to confirmthat the required clean-up had beenachieved. With the scavenger injection rateset at the maximum expected H2S level(and hence an initial massive overdosing),the results shown in Fig. 10 were obtained.Throughout the test, as the amount ofoverdosing decreased with increasing H2Slevel in the produced gas, an average H2Sreduction (product yield) of 97% wasachieved at the expense of an overall aver-age dosage of 20 L/kg H2S. Again, noincrease in pressure drop across the flow-line was observed, but a camera-runrevealed the presence of thick sludge layeron the bottom of the flowline and ran-domly deposited cauliflower-like deposits(Fig. 11). Overdosing to achieve the target-ed H2S reduction was not the way forward.The disappointing product yield at higherthan expected dosage requirements seenin the first test also indicated that an alter-native approach was required to reach ourobjectives.

Challenge of Chemical Delivery MethodFollowing a period of consultation withBaker Petrolite, the suitability of the hith-erto used chemical delivery method waschallenged. Preceding field tests had usedan atomization nozzle specifically designedto avoid the blockage problems experi-enced some years earlier with the conven-tionally designed nozzles. Design reviewraised the suspicion that an inefficientatomization process might be the key con-tributing factor to the problems experi-enced. It was proposed to utilize Bete® PJseries direct-pressure atomization nozzles,adapted to allow the use of high-pressuregas to boost the velocity in the atomizernozzle. Both laboratory and field evalua-tion of such gas-assisted (2-phase) atomiza-tion nozzles had shown approximately30% efficiency improvement over the nor-mal single phase atomization.

Again, utilizing sequential high-pres-sure water jetting and acidization, theflowline was cleaned (confirmed through a camera-run) and a 2-phase atomizationnozzle installed, the high-pressure gasbeing delivered via nitrogen batteries.Injection was subsequently initiated, initial-ly at the supplier recommended product

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Baker PetroliteDeveloping Low Sour-Gas Reserves with Direct-InjectionLiquid Hydrogen Sulfide Scavengers

Fig. 12 Results of 2-phase atomization trial with Product SX2686

dosage and gas-assist pressure of 20-25bars above the flowing tubing head pres-sure. Results of this next test are providedin Fig. 12. The percentage H2S removal ini-tially obtained with the 2-phase atomizerwas disappointing. However, scavengingperformance could be improved by chang-ing product injection rates and nozzlesizes.

Ultimately, the desired reduction in H2Swas achieved, but only at a high productdosage of some 20 L/kg H2S. By reducingthe gas-assist pressure to only 2-3 barabove the flowing tubing head pressure,an H2S reduction (product yield) >99%could be consistently achieved at a productdosage of approximately 15 L/kg H2S. Thisresult was maintained at the end of thetest, when the gas-assist needed to beshut-in due to depletion of the nitrogenbatteries. A subsequent camera-runthrough the flowline showed the completeabsence of any scale deposits or sludge.

Mitigation of scale build-up in theflowline was only one of the two objectivesthat were successfully met by the use ofthe gas-assisted atomizer. The other objec-tive was to obtain higher scavenging effi-ciencies as was observed in previous

laboratory and field trials using the gas-assisted atomizer. However, further evalua-tion indicated that such increasedscavenging efficiencies were primarilyobserved in low-pressure systems withoperating pressures less than 5 to 10 bar. Inthe Coevorden field, the operating pres-sures were significantly higher, rangingfrom 35 to 75 bar. The higher pressure isthought to be the key contributing factorin not achieving further improvement inscavenging efficiency using gas-assistedatomization. The matter was not furtherpursued, principally because very few ofthe locations targeted for developmenthad gas available at sufficiently high pres-sure to achieve 2-phase atomization (imply-ing a compression requirement) andcommercially available nitrogen gas gener-ators could not deliver the required pres-sures. Given the observation at the end ofthe last test that product yield could bemaintained without gas-assist, the decisionwas made to carry out an additional trial.

Prior to discussing this additional trial,it is of interest to revisit the trial discussedabove. The influence of the linear gasvelocity on the product yield is shown inFig. 13. As earlier, the observed data have

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Fig. 13 Calcium Carbonate scale in flowline

been fitted to a calculated trend utilizingHolt’s two-parameter linear exponentialsmoothing method.4 Comparing with previ-ously obtained results (in which differentatomization nozzles are compared), it isagain seen that the product dosage (andhence injection rate) seems to have littleinfluence. In this test, the linear gas veloci-ty did not enter the region lower than 4 m/s where the earlier test showed evi-dence of the existence of a threshold limit-ing velocity value. A more rigorousexamination of the data obtained from the current test revealed that they could be fitted to the equation:

Product yield (%) = m*linear velocity(ms-1) + b (r2 = 0.71)

through linear regression analysis with thesame mean absolute percentage error asthe fit obtained with Holt’s method.

Dual InjectionIn gas systems where short contact timesand high H2S loading are present chal-lenges to efficient reduction in H2S, injec-tion of chemical at multiple injectionpoints has often been used to improve thescavenging efficiency. After the 2-phaseatomizer trial, a dual-injection approachwas utilized in the Coevorden system byinjecting the chemical both at the wellheadand at the test header. Use of dual injec-tion resulted in >99% removal of H2S andthus yielded the desired results in scaveng-ing efficiency. Improved scavenging effi-ciency in a multiple injection system (in thiscase two-point injection) can be explainedas follows. First, the volume of scavengerinjected at the first injection point (well-head) is typically less than the stoichiomet-ric amount needed to react with the totalH2S in the gas. Presence of scavenger inlimiting quantities allows for optimum uti-lization of the scavenger. Therefore, scav-enger injection at the first point removedthe bulk of the H2S (75–85% reduction).Second, injection of the scavenger at thesecond point (test header) provides a pol-ishing or finishing effect. The neat high-strength scavenger contacts the lean gas(low in H2S) to react with the residual H2Smolecules that were not removed after thefirst scavenger injection. The limiting reac-tant at the second point is the H2S and canbe removed by the high concentration of

the scavenger. The dual-injection systemusing SX 2656, applied through single-phase Bete® nozzles, yielded removal efficiencies in the range of 99%, reducedscavenger consumption to, on average 9 L/kg H2S, and provided effective controlof calcium carbonate scaling.

Current Development StatusPrior to the high gas nomination period ofWinter 2000/2001, two satellite locations ofthe Coevorden-17 gas treatment plantwere converted to facilitate the productionof low-sour gas wells with H2S levels of upto 220 ppm(v) through dual-injection of SX 2656. An extended optimization pro-gram, through which overall productdosages of as low as 7 L/kg H2S could beachieved as well as consistent productyields of >99%, is coupled with furtherinvestigation of the operating parametersaffecting the scavenging reaction.

The following observations show thatH2S scavenger injections systems must bespecifically designed for each well. WellCoevorden-31 produces gas at an initialrate of 420,000 Nm3/day, gradually declin-ing to 310,000 Nm3/day at a constant flow-ing tubing head pressure of approximately90 bar and with a constant H2S concentra-tion of approximately 220 ppm(v). The lin-ear gas velocity is in the range 9-12 m/s.Injection of SX 2656 at the wellhead alonedoes not result in the desired H2S reduction(product yield), and it needs to be aug-mented with a second point injection atthe main production header. At anothersatellite location, well Coevorden 36 pro-duces gas at a fairly constant rate of400,000 Nm3/day at a flowing tubing headpressure of 70 bar and with a constant H2Sconcentration of 220 ppm(v). The linear gasvelocity is approximately 6 m/s. Injection ofat the wellhead alone yields the desiredH2S reduction, and at this location no sec-ond point injection is required. As otherwells are being brought on stream, moredata can be gathered to hopefully unravelthe apparently complex role of interlinkedprocess parameters on the physical chem-istry of direct-injection hydrogen sulfidescavenging.

No evidence of scale formation hasbeen encountered to date at any of thelocations where it is being applied.

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Baker PetroliteDeveloping Low Sour-Gas Reserves with Direct-InjectionLiquid Hydrogen Sulfide Scavengers

Chemical costs are approximately US$ 11per kg H2S (slightly lower or slightly higherin individual cases). Back-up facilities utiliz-ing product B (in pipeline-dry export gastreatment) are required during well start-up, but only when fast production ramp-ups are employed. The benefits5 ofautomation of the hydrogen sulfide chemi-cal scavenger injection systems, combiningcurrently available technology into a multi-faceted cost saving and reliable tool, arerecognized and its economic implementa-tion is being pursued.

Conclusions1. Selection and application of direct-injec-tion liquid hydrogen sulfide scavengersrequires an understanding of the funda-mental relationships between operatingparameters and scavenging (physico-)dynamics.2. More fundamental research, preferablyexecuted ‘in the field,’ is required tounequivocally identify these relationshipsand to allow ‘Best in Class’ design of treat-ment applications.3. In applying direct-injection liquid hydro-gen sulfide scavenging technology, a sys-tematic as well as a systemic approach,with continuing challenge of chemical sup-plier claims, is required to achieve thedesired results.4. Mutually beneficial solutions to prob-lems can be found between operatingcompanies and their preferred chemicalsuppliers by not concentrating on internal-ly focused commercial ambitions but byconcentrating on: “solving this problemtogether, regardless,” and reaping thebenefits of such solutions.

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AcknowledgmentWe thank NAM and Baker Petrolite fortheir permission to publish this paper. In particular, very special thanks go toNAM’s operations staff, not only for pro-viding gas treatment plants and fieldpersonnel to support this project whilemaintaining active productionoperations, but more importantly alsofor their continuing support and dedica-tion in the face of adversity. We haveexceptional pride in mutual refusal toyield. This article is based on paper SPE71541 (see reference 6).

About the Authors:

J.G. R. Eylander joined Shell as a physical chemist in1975. Following six years of fundamental researchinto the dynamic interfacial properties of crudeoil/water systems at Shell’s Rijswijk research labora-tories in the Netherlands, he was transferred to theProduction Technology department. Followingassignments in Shell operating units, he was trans-ferred to the Nederlandse Aardolie Maatschappij(NAM) in 1995 as Senior Production Chemistry andShell Global Production Chemistry consultant.

Hanneke Holtman is currently a maintenance engineer with the Groningen Long Term team inNAM. She joined NAM in 1999 after attaining aMechanical Engineering degree from the GroningenHogeschool, the Netherlands. During her firstassignment as an Operations Engineer, she activelyparticipated in the team responsible for implement-ing H2S scavenging technology and operation with-in NAM.

Tauseef Salma is the group leader for Microbiocidesand H2S Scavenger Technologies for Baker Petrolite.Dr. Salma obtained her B.S. degree in ChemicalEngineering from University of Engineering andTechnology in Lahore, Pakistan, and Ph. D. inChemical Engineering from Rice University in 1997.

Mingdong Yuan is the Oilfield Scale group leader atBaker Petrolite. Mr. Yuan obtained his B.S. degreein Applied Chemistry from Southwest ChinaPetroleum Institute in 1982 and Ph. D. in PetroleumEngineering from Heriot-Watt University in 1989. Heconducted postdoctoral research at Heriot-Watt forfive years and joined Baker Petrolite in 1994.

James Johnstone is the NAM Account Manager forBaker Petrolite. Mr. Johnstone obtained his BSc.(Hons) degree in Chemistry from AberdeenUniversity. He has over ten years of experience inoffshore oil & gas industry in the U.K., Norway,Denmark and Netherlands.

References:

1. Dillon, E.T., “Composition and method for sweet-ening hydrocarbons,” U.S. Patent no. 4,987,512,December 1990.

2. Bhatia, K., Thomas, A.R. & Sullivan, D.S., “Methodof treating sour gas and liquid hydrocarbonstreams,” European Patent Application 94305225.8,February 1995.

3. Fisher, K., “Initial results from GRI’s 30 MMscf/daydirect-injection H2S scavenging test facility,” paperpresented at the Eighh Gas Research Institute SulfurRecovery Conference, Austin, Texas, October 1997.

4. Kvanli, A.H. et al, Introduction to BusinessStatistics, West Publishing Co., 1992, p. 745 f(f).

5. Roth, D. et al, “Automated Chemical Control ofH2S Content of Natural Gas,” paper SPE 67247, pre-sented at the SPE Production and OperationsSymposium, Oklahoma City, Oklahoma, 24-27 March2001.

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