Copyright 2000, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2000 SPE International Symposium onFormation Damage Control held in Lafayette, Louisiana, 23–24 February 2000.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractThis paper describes the development of acidizing systemsthat use several different aldehyde-based sulfide suppressionchemicals in conjunction with new acid corrosion inhibitors.Specific combinations of these chemicals have allowed theacid to dissolve FeS, suppress H2S and still enable the acid tobe inhibited to industry corrosion standards. Laboratory testsinclude dissolution of FeS, measurement of H2S evolved,measurement of acid concentration and chloride ionconcentrations. We also determined the effect of FeS and H2Son the corrosion of oilfield steels with these additives.Laboratory measurements covered the temperature range from75 to 275 oF (reservoir temperature). Experimental results were compared with that previouslypublished data.1 The new system enabled the acid to dissolvemore FeS than fluids containing previously tested suppressors,while controlling H2S evolution and corrosion. During field testing, samples of the spent acid werecaptured and were analyzed for [Fe], [S2-] and [HCl]. The datawill contribute to an understanding of the corrosion processesand sulfide control during acid treatments. The field acidtreatments were accomplished successfully without significantchanges in procedures and resulted in large increase in gasproduction. This system is designed primarily for "tubecleaning" operations prior to acid stimulation (matrix andfracture acidizing), but the control chemicals have also beentested for use in the actual stimulation fluid stages. The new chemicals and procedures will allow theoperators to safely remove large amounts of fouling deposits,while controlling the toxic and corrosive effects of H2S muchmore effectively than previously used products.

IntroductionIn many wells, pipelines, or in the hydrocarbon processingunits of refineries, iron-based surfaces may come into contactwith sulfur-containing fluids. At the temperatures present inthe various sections or reactors, and during long periods ofcontact, iron sulfide deposits (generally FeS, but sometimes,FeS2) will form. The reduced sulfur minerals withapproximately 1:1 Fe/S mol ratios (makinawite, troilite,pyrrhotite) can be dissolved using mineral acids, while pyriteand marcasite (FeS2) have low acid solubility.2

While scale removal using mineral acids is a very effectiveprocedure, it produces large amounts of hydrogen sulfide.

FeS + 2H+ = Fe2+ + H2S (1).

Hydrogen sulfide causes severe safety and operationalproblems once the acid leaves the system being treated, andH2S stimulates corrosion of the base metal. For pipelines or inrefinery operations, surface cleaning is the major goal of theoperation. Lawson et al.3 reviewed the major procedures forsafely removing iron sulfide deposits: 1) mineral acids with anacid-gas scrubber; 2) mineral acids with hydrogen sulfidesuppression chemicals; 3) multiple stages of oxidizing agentswith acids; and 4) alkaline cleaners. Several different suppression technologies have beendeveloped for surface cleaning operations. Frenier and co-workers4-6 and Buske7 developed suppression chemicals thatcontain aldehydes. The most efficient agent is formaldehyde,which reacts stoichiometrically with hydrogen sulfide toproduce trithiane, a very insoluble material.8

In treating sour oil and gas wells, as compared with treatingsurface equipment, corrosion suppression (not elimination ofsulfide gas) and dissolution of FeS are of major concern. Theinhibitor package must protect several types of steel at hightemperatures in the presence of concentrated acid containingnumerous additives. The various additives are required sincethe purpose of the treatment may include removal of inorganicand organic damage from producing formations (matrixtreatments). Tubular cleaning prior to acidizing the formation iscommonly performed and is strongly recommended.9,10

During acidizing treatments, the control of iron and sulfurprecipitation is an important requirement. The control is

SPE 58712

Investigation of Sulfide Scavengers in Well Acidizing FluidsH.A. Nasr-El-Din, SPE, A.Y. Al-Humaidan, SPE, B.A. Fadhel, Saudi Aramco, W.W. Frenier, SPE and D. Hill, SPE,Schlumberger

2 H.A. NASR-EL-DIN ET AL. SPE 58712

necessary to prevent formation damage due to precipitation ofiron compounds and elemental sulfur. As the acid spends oncarbonate surfaces, ferric iron precipitates at pH > 1.5,10 andferrous iron precipitates at pH values > about 6.0. Elementalsulfur can precipitate if ferric iron is present:9

Fe3+ + S2- = Fe2+ + So (2).

As the pH rises above 1.9, any residual iron can react withsulfide ions to re-precipitate FeS.11

Fe2+ + S2- = FeS (3).

Iron sulfide and elemental sulfur have been implicated inproduction declines following acid treatments. For thesereasons, acid treatments of sour wells have a number of goalsand requirements for success:1. Dissolution of any FeS (or other sulfides) already present,2. Elimination of reprecipitation of solids after completion

of the acidizing procedures,3. Suppression of formation of H2S during acid dissolution

of FeS, and4. Control of corrosion to well tubulars during the acidizing

process. Iron control during acidizing treatments can be achieved byadding chelating agents (citric acid, NTA, etc.) or by usingreducing agents (sodium erythorbate). Crowe12 patented acombination of chelating and reducing agents tosimultaneously prevent iron and sulfur precipitation in spentacids. This technology may control the reactions in Equations2 and 3. The combination of reduction and chelation shouldcontrol all of the solids as the pH rises to > 1.9. Hall and Dill13

reviewed a number of precipitation controlmethods for sour and sweet wells. They acknowledged thatchelating agents are effective in controlling iron precipitation,but advocated the use of a “sulfide modifier”, NTA andethyleneglycol monobutylether (EGMBE) to treat sour wellscontaining iron. Dill and Walker14 claimed a combination of achelating agent (NTA) and an aldehyde (aldol) for controllingiron and sulfur precipitation. Walker et al.9 expanded on thisconcept and noted that iron control agents are not requiredduring tube clean-out procedures. However, they advocatedthe use of a "sulfide scavenger". This material apparently isthe "sulfide modifier" endorsed previously by Hall and Dill.13

Walker et al. also claimed that the reducing agents describedby Crowe12 are not effective in 15 wt% HCl. Ford et al.2

advocated well clean-out procedures using only the acid andthe sulfide scavenger. However, in the case historiesdescribed, the acid formulation was injected directly into theformation. Williamson15 claimed the use of a chelating agent and aketone for the same types of treatments for which the Walkeret al.9 acid formulations are used. Kasnick and Engen16

advocated acid washing of the tubing prior to formationacidizing treatment of a deep gas well in Saudi Arabia. Nomention of sulfide control was made. Nasr-El-Din et al.17,18

studied various additives for stimulating sandstone through

sour water injectors. A 7.5 wt% HCl solution was effective inremoving FeS and biomass. A sulfide scavenger tested (butnot named) did not damage the cores. Al-Humaidan and Nasr-El-Din1 examined a number ofsulfide scavengers at ambient conditions. None of thecommercial formulations were as effective as formaldehyde.In addition, they found that most of these scavengersadversely affected acid reactions with iron sulfide scale,especially at high scavenger concentrations. Therefore, theobjective of this work is to identify a scavenger or a mixtureof scavengers to improve suppression of H2S evolution whilepreserving the high dissolution of FeS as well as controllingcorrosion up to 275 oF.

Experimental ProceduresThree sets of experiments were conducted. The first set wasdone at atmospheric pressure and temperature of 25 °C. Thesecond set was also done at atmospheric pressure, however,the test temperature was 150 °F. The third set was done at atemperature of 275 °F and a pressure of 3000 psi. Theexperimental set-ups and procedures used are explained in thefollowing sections.

Experimental set-up and test procedure used atambient conditions. The first set of experiments wasperformed at ambient conditions. The set-up consisted of areactor and two absorbers.1 The reactor initially contained aknown amount of iron sulfide. Then, hydrochloric acid withvarious chemicals was added to the reactor. The absorbers areconnected in series and contained a cadmium sulfate solutionat a concentration of 10 wt%. Iron sulfide particles with a diameter less than 75 microns(200 mesh) were used. A predetermined amount of ironsulfide particles (typically 1 g) was placed in the reactor.Then, five g of 7.5 wt% hydrochloric acid with additives werepoured on the solids. In all experimental runs, a hydrogensulfide scavenger was added to the acid just prior to theexperiment. The effectiveness of various hydrogen sulfidescavengers was studied over a wide range of concentrations.The reactants were continuously mixed using a magneticstirrer. The reaction was allowed to proceed for two hoursthen the liquid and solids phases present in the reactor wereseparated and analyzed. To determine the amount of H2S gas produced from thereaction between iron sulfide and hydrochloric acid, the gaspasses through the cadmium sulfate solution, which is presentin the absorbers. Hydrogen sulfide reacts with cadmiumsulfate and produces a yellow precipitate of cadmium sulfide.The amount of hydrogen sulfide released was determined fromthe weight of cadmium sulfide. The concentrations of key ions in the aqueous phase in thereactor (supernatant) were measured. Chloride was measuredby titration with a 0.1N silver nitrate solution. Ironconcentration was measured by Inductively Coupled Plasma-Emission Spectroscopy (ICP-ES). Acid concentration wasmeasured by titration with a 0.1 N NaOH solution. Sulfide ion

SPE 58712 INVESTIGATION OF SULFIDE SCAVENGERS IN WELL ACIDIZING FLUIDS 3

was measured using the iodometric method.

Experimental set-up and test procedure used at 150°°F. The second set of tests was conducted at 150 °F andatmospheric pressure. The experimental set-up consisted of athree neck reaction flask equipped with a dropping funnel,heating mantle/temperature controller and a mechanical stirrer,Fig. 1. The dropping funnel was used for efficient addition ofall acid solutions containing all additives. The mechanicalstirrer was used for efficient mixing of the acid with thepowdered iron sulfide. The acid gases produced by thereaction were swept to a scrubber containing 300 cm3 of a 3wt% NaOH solution. Two ratios of acid to FeS were used: 200g acid to 3 g FeS, 108 g acid to 10 g FeS. Two grades of FeS were used: 1) a technical grade with aparticle size of about 40 mesh; and 2) a purified (99.9 wt%)grade with a particle size of 100-200 mesh. The acid washeated to the test temperature, and the FeS particles wereadded and the solution was stirred with a mechanical bladestirrer. In selected tests, an L-80 coupon was inserted tomeasure the corrosion of the test fluid. The designations of theadditives are given in Table 1.

Experimental set-up and test procedure used at 275°°F. the third set of tests was performed at 275 °F and 3,000 psiin a small, high temperature corrosion autoclave at Stim-Lab,Duncan, OK. Iron sulfide scale (1.2 g) was added to 100 mLof 7.5 wt% HCl inhibited with 1% Acid Corrosion Inhibitor B+ 2% Inhibitor Aid (formic acid). At the conclusion of thetest, the pressure was cautiously bled and the produced gaseswere bubbled through 300 cm3 of a 3 wt% NaOH solution.The concentrations of iron and sulfur were determined in theresidual acid (supernatant) and the sodium hydroxide solution,respectively, and the scavenging efficiency was determined.

Corrosion Inhibition. Additional corrosion tests werecompleted with L-80 steel coupons exposed to 7.5 wt% HClinhibited with Inhibitor B and Inhibitor Aid as described forthe above tests. Corrosion tests were completed at 275 °F and5,000 psi for four hours contact time at temperature. Standardcorrosion autoclave test procedures were employed.19 Themaximum allowable corrosion rate recommended for thesetest conditions is 0.05 lb/ft2 with no unacceptable pitting.Acceptable pitting is represented by a pitting index of 3 orless.

Results and DiscussionPerformance of the scavengers at ambient conditions. Al-Humaidan and Nasr-El-Din1 examined several hydrogensulfide scavengers that can be used during acidizingtreatments. They found that formaldehyde was very effectivein their experiments. Formaldehyde, however, has limited usein the oil industry because it is carcinogen. One way toovercome this problem is to use hexamethlyenetetraamine(HMTA) which reacts with HCl to produce formaldehyde.5

N N

N

N

+ 4 H H 2 O+6 CH 2 O6 + 4 NH 4

Hexamethylenetetraamine (4)

The performance of HMTA was evaluated by adding 5 g of7.5 wt% HCl to 1 g of FeS particles. The efficiencies ofcapturing hydrogen sulfide and dissolving FeS weredetermined as described in Reference 1. It is worthmentioning that 43.2 wt% of FeS should be dissolved by theamount of the acid used. Fig. 2 shows the efficiencies ofcapturing hydrogen sulfide and dissolving FeS as a function ofthe initial HMTA concentration. The efficiency of capturinghydrogen sulfide was relatively high. However, the efficiencyof dissolving FeS was 19% at 0.2 wt% HMTA. It decreasedand reached 12.6% at 8 wt% HMTA. These results indicatethat most of the acid did not react with the FeS. As a result,the amount of H2S released was low. The concentration of the acid in the supernatant wasmeasured. Fig. 3 shows the variation of HCl concentration asa function of the initial HMTA concentration. Acidconcentration was 3.6 w/v% at 0.2 wt% HMTA and decreasedto 0.5 at HMTA concentration of 8 wt%. At low HMTAconcentrations, the amount of formaldehyde available is small.As a result, hydrogen sulfide accumulates and the rate ofreaction of the acid and FeS diminishes. At high HMTAconcentrations, a large portion of the acid reacts with HMTA,and, as a result, the concentration of HCl in the supernatantdiminishes. Several important points should be noted in Figs. 2 and 3.First, the efficiency of capturing hydrogen sulfide can bemisleading. The efficiency of dissolving iron sulfide should beconsidered simultaneously. HMTA consumes a portion of theacid used. This amount should be considered when designinga formula for field application. Finally, HMTA is not aseffective as formaldehyde. This point will be further discussedin the following sections. Other aldehyde-based chemicals were also examined. Theefficiencies of capturing hydrogen sulfide and dissolving FeSin the presence of Aldehyde B, Table 1, are shown in Fig. 4 asa function of the initial scavenger concentration. Theefficiency of capturing hydrogen sulfide increased with thescavenger concentration up to 5 wt% Aldehyde B, thenremained constant. The efficiency of dissolving FeS slightlydecreased with the scavenger concentration, then remainedconstant. A comparison of the results shown in Figs. 2 and 4 clearlyindicate that the performance of Aldehyde B is significantlybetter than HMTA. This conclusion is further confirmed byexamining acid concentration in the supernatant in thepresence of Aldehyde B, Fig. 5. Acid concentration was 0.3w/v% at 0.25 wt% Aldehyde B. It increased to 1.4 w/v% atAldehyde B concentration of 8 wt%. These values are

4 H.A. NASR-EL-DIN ET AL. SPE 58712

significantly less than those obtained in the presence of lowconcentrations of HMTA. At high scavenger concentrations,acid concentration in the supernatant of HMTA solutions waslower. This is because of the acid reaction with HMTA. Previous studies have indicated that formaldehyde is themost effective scavenger. It is of interest to compare theperformance of several aldehydes examined in the presentstudy with that of formaldehyde. Fig. 6 compares theefficiency of capturing hydrogen sulfide obtained withAldehyde A, B and HMTA with that obtained withformaldehyde. The efficiency of capturing hydrogen sulfide ishighest when HMTA was used. However, this trend ismisleading as mentioned before. The efficiency offormaldehyde to capture hydrogen sulfide is higher than thatobtained with Aldehyde A or B, especially at high initialscavenger concentrations. The efficiency of capturing H2Susing Aldehyde A is nearly similar to that obtained withAldehyde B. Fig. 7 compares the efficiency of dissolving FeS in thepresence of various scavengers. HMTA has the lowestefficiency, whereas formaldehyde has the highest efficiency.Aldehyde B has a slightly better efficiency than Aldehyde A. The results shown in Figs. 6 and 7 indicate thatformaldehyde is the most effective aldehyde. HMTA is not asefficient as formaldehyde. Aldehydes A and B have nearlysimilar performances.

Performance of the scavengers at 150 °°F. The resultsdiscussed so far were obtained at room temperature. It is ofinterest to examine the performance of various scavengers atelevated temperatures. Figs. 8 and 9 show the percentage ofFeS dissolved and H2S evolved (as measured by the amount ofsulfide in the NaOH solution) for a set of tests conducted at150 oF, which used 10 g of 200 mesh FeS and 108 g of 7.5wt% HCl. There was just enough acid to dissolve the entireiron sulfide sample. The control acid (no additives) dissolvedalmost 95 wt% of the sample and there was 0.31 wt% S (totalS by X-ray diffraction) in solution. This value was used as thesaturation value for the supernatant and compared favorablywith the literature value of 0.4 wt% H2S in HCl.20 Values >0.31 wt% indicate that the scavenger is holding some sulfur insolution. The weight used of each aldehyde is the theoreticalamount needed to scavenge all H2S that could be producedfrom acid reaction with iron sulfide. All of the aldehydes examined maintained more sulfur insolution than the control, Fig. 9. They also reduced total FeSdissolution to some extent, especially Aldehydes C and D. Theformaldehyde test deserves more explanation. In the presenceof hydrogen sulfide, trithiane is formed:

3 CH2O + 3 H2SH S S

S

Formaldehyde Hydrogen Sulfide Trithiane

H2O + 3

(5)

This material is insoluble in acid and thus takes some of thesulfur out of the solution (supernatant). Aldehyde A alsoproduced some solids after the acid cooled, but not as much asformed with formaldehyde. Aldehyde B did not produce anysolids, even when the acid cooled to room temperature.Aldehydes A and B were the most effective scavengers tested.Similar to the results obtained at room temperature, HMTAwas not as effective as predicted from literature.5 However,even when an equivalent amount of additional HCl was added,it was not as effective as Aldehydes A or B. We also see that Aldehydes A and B interfered with thedissolution of FeS. More FeS dissolved in the presence ofAldehyde B. This is similar to the results obtained at roomtemperature. A mixture of 15 g Aldehyde A and 1 g AldehydeD allowed much more FeS to dissolve than the 2 vol%Aldehyde D test. It is worth noting that Corrosion Inhibitor B did inhibit thedissolution of FeS to some extent. This is in agreement withrecent studies conducted by Nasr-El-Din et al.21 on the effectof acid additives on acid reaction with iron sulfide scales. The second type of tests employed 200 cm3 of 7.5 wt%HCl as a solvent for 3 g of the technical grade (40 mesh max)FeS. This amount of FeS should yield about 1 wt% Fe insolution, and is considered to be a good model for the amountof iron expected in most tube cleaning operations (if the entirevolume of acid in the tubing is used as the mount used in thecalculation). All tests were run at 150 oF and lasted for fourhours. In some tests, a weighed L-80 corrosion coupon wasplaced in the flask so that a corrosion rate could bedetermined. The results are displayed in Fig. 10. Corrosionrates for these tests are given in Table 2. All of the solventcombinations dissolved at least 83 wt% of the scale. Manyformulations dissolved 100 wt% of the deposit. All of themscrubbed essentially all of the H2S produced. The Aldehyde B-based solutions were more corrosive than the Aldehyde A-based solutions. Addition of Aldehyde D reduced thecorrosion rate in the presence of Aldehyde B. The formulationwith Aldehydes B and D and Inhibitor B looks like anexcellent compromise. Aldehyde scavengers react with H2S toproduce complex sulfides (Eq. 5 is a special example). It is ourobservation that "oils" of undefined compositions, frequentlyform. The Aldehyde B solutions always had less black oil thanthe Aldehyde A or C solutions. Some of the test solutions hada wetting agent (Surfactant A) and an iron control agent(NTA) to simulate some field formulations.

Evaluation of corrosion inhibition at 275 °°F. Acceptablecorrosion inhibition for L-80 steel coupons was achievedusing 0.6% Inhibitor B and 2.0% Inhibitor Aid. The test wasconducted using 7.5 wt% HCl and the coupons were exposedto the acid for four hours at 275 °F in an H2S environmentcontaining an equivalent concentration of 0.5 mol% H2S.Corrosion data are shown for Aldehyde B and Aldehyde A incombination with Aldehyde D at a 10/1 volume ratio Table 3.The addition of Aldehyde D is necessary for achievingacceptable corrosion protection at this temperature.

SPE 58712 INVESTIGATION OF SULFIDE SCAVENGERS IN WELL ACIDIZING FLUIDS 5

Performance of the scavengers at 275 °°F. At theconclusion of the corrosion tests completed at 275 °F, selectedsamples were submitted for total iron and sulfur analyses.Results of these analyses are shown in Tables 4 and 5 forAldehyde B and Aldehyde A with varied surfactants,respectively. Results show high FeS dissolution. Theseresults clearly show that greater than 80 wt% dissolution ofthe FeS is observed with the use of Aldehyde B or AldehydeA. The iron and sulfur analyses are frequently observed to behigher than 100%, based on the quantity of FeS added to thetest. These observations are attributed to the high temperaturetest and some of the water may have evaporated during the testand ions may have been concentrated, resulting in valuesgreater than 100%. A closer evaluation of the test procedureand analyses are planned. Please note that high iron and sulfurcontent is desirable for this test procedure. A high [Fe] contentsignifies high FeS dissolution. On the other hand, high [S]content indicates good scavenging of the aldehyde used. Thisis a direct analysis of the acid following the corrosion tests andillustrates the high solubility of the scavenged sulfur products.One conclusion is clear: Aldehyde B and Aldehyde A are botheffective in controlling H2S and high solubility of FeS isachieved for these test conditions.

Field application. Based on extensive lab studies, it wasdecided to use HCl to pickle the tubing of a deep gas well in asour carbonate reservoir in Saudi Arabia. Acid additivesincluded Corrosion Inhibitor B, Inhibitor Aid (formic acid),and a mixture of Aldehyde B and Aldehyde D, Table 6. Theacid volume was 5000 gals and acid concentration was 20wt%. The acid was pumped in the well tubing and displacedusing low sulfate water. Once the acid reaches the bottom ofthe tubing, the well was allowed to flow back. Samples of thereturn fluids were collected each two minutes. Hydrogensulfide content was determined on site using the iodometricmethod, and the concentration of ferrous iron was determinedusing the method described by Taylor et al.22 Theconcentration of key ions were also determined and the resultsare given in Table 7. Initial samples contained lowconcentrations of sodium, calcium and magnesium. Thesesamples represent the low salinity water that was used todisplace the pickle acid down the well tubing. Samplescollected after one hour contained live acid. Theconcentrations of Fe+2 and Fe+3 were relatively high in thesesamples. Hydrogen sulfide concentration values increasedsomewhat with the arrival of the acidic samples. It isinteresting to note that the concentration of Fe+2 in the lastsample reached 4800 mg/L. This amount corresponds tonearly 2750 mg/L of sulfide ion. Field measurements indicatethat the concentration of sulfide is only a fraction of this value.These results confirmed that the acid system used in this wellwas capable of scavenging a large amount of hydrogen sulfideproduced. In addition, iron concentrations in the flowbacksamples collected after the main acid treatment were low,which confirmed that the pickling acid did dissolve most ofthe corrosion products present in the well tubing. The acid

formula given in Table 6 was also used in three more wells.And similar trends were obtained. In addition, the main acidtreatment has resulted in significant increases in gasproduction.

Conclusions1. The preponderance of the above data supports our

recommendation that use of Aldehyde B with Aldehyde Dis the overall best choice, considering FeS dissolution,corrosion and production of organic oil.

2. Aldehyde A is also effective in scavenging H2S; however,visual observations of experiments completed attemperatures ≤ 150 °F reveal more oil residue formedduring the test than observed for tests completed withAldehyde B.

3. Field results confirmed that the mixture of Aldehyde Band Aldehyde D was effective in reducing the amount ofhydrogen sulfide released. Meanwhile they did notsignificantly affect acid reactions with iron compoundspresent in the well tubing.

AcknowledgmentsThe authors wish to acknowledge the Saudi Arabian Ministryof Petroleum and Mineral Resources, the Saudi Arabian OilCompany (Saudi Aramco) and Schlumberger, LTD forgranting permission to present and publish this paper. Theauthors would like to thank Mr. R.M. Saleh for performingsome of the experimental work. ULU and SALD of SaudiAramco conducted chemical analysis of the acid returnsamples.

References1. Al-Humaidan, A.Y. and Nasr-El-Din, H.A.:"Optimization

of Hydrogen Sulfide Scavengers Used During WellStimulation," paper SPE 50765 presented at the 1999 SPEOilfield Chemistry held in Houston, TX, February 16-19.

2. Ford, W.G.F., Walker, M.L., Halterman, M.P., Parker,D.L., Brawley, D.G., and Fulton, R.G.: “Removing aTypical Iron Sulfide Scale: The Scientific Approach”,paper SPE 24327 presented at the 1992 SPE RockyMountain Regional Meeting held in Casper, WY, May18-21.

3. Lawson, M.B., Martin, L.D. and Arnold, G.D.:“ChemicalCleaning of FeS Scales,” Paper 219, Corrosion/80, NACEheld in Houston, TX, March 1980.

4. Frenier, W.W. et al.: “Composition and Method forRemoving Sulfide-Containing Scale from Surfaces,” USPatent 4,220,550, 1980.

5. Frenier, W.W.:“Method and Composition for RemovingSulfide-Containing Scale from Metal Surfaces,” USPatent 4,310,435, 1982.

6. Ball, C.L. and Frenier, W.W.: “An Improved Solvent forIron Sulfide Deposits,” Paper 2, Corrosion/84, NACE,Houston, TX, April, 1984.

7. Buske, G.R.: “Method and Composition for RemovingSulfide-Containing Scale from Metal Surfaces,” US

6 H.A. NASR-EL-DIN ET AL. SPE 58712

Patent 4,289,639, 1981.8. Van Dijk, J. and Bos, A.: “An Experimental Study of the

Reactivity and Selectivity of Novel Polymeric “Triazine-Type” H2S Scavengers”, Presented at the Chemistry inIndustry Conference, Royal Society of Chemistry, 1998.

9. Walker, M.L., Dill, W.R., Besler, M.R., and McFatridge,D.G.: “Iron Control in West Texas Sour-Gas WellsProvides Sustained Production Increases”, JPT (May1991) 603.

10. Taylor, K.C., Nasr-El-Din, H.A. and Al-Alawi, M.:“Systematic Study of Iron Control Chemicals UsedDuring Well Stimulation”, SPEJ, 4, 19-24, 1999.

11. Crowe, C.W.: “Evaluation of Agents for PreventingPrecipitation of Ferric Hydroxide from Spent TreatingAcid”, JPT (April 1985) 691.

12. Crowe, C.W.: "Method of Preventing Precipitation ofFerrous Sulfide and Sulfur During Acidizing," US patent4,633,949, 1987.

13. Hall, B.E. and Dill, W.R.: “Iron Control Additives forLimestone and Sandstone Acidizing of Sweet and SourWells,” paper SPE 17157 presented at the 1988 SPEFormation Damage Control Symposium held inBakersfield, CA, February 8-9.

14. Dill, W.R. and Walker, M.L.: "Composition and methodfor Controlling Precipitation When Acidizing SourWells", US Patent 4,888,121, 1989.

15. Williamson, C.D.:"Precipitation Control", US patent5,126,059, 1992.

16. Kasnick, M.A. and Engen, R.J.: “Iron Sulfide Scaling andAssociated Corrosion in Saudi Arabian Khuff Gas Wells,”paper SPE 17933 presented at the 1989 SPE Middle EastOil Technical Conference and Exhibition held in Manama,Bahrain, March 11-14.

17. Nasr-El-Din, H.A., Al-Anazi, H.A. and Hopkins, J.A.:"Acid/rock Interactions During Stimulation of Sour WaterInjectors in a Sandstone Reservoir," paper SPE 37215presented at the 1997 SPE Int. Symposium on OilfieldChemistry held in Houston, TX, February 18-21.

18. Nasr-El-Din, H.A., Rosser, H.R. and Hopkins,J.A.:”Stimulation of Injection Water Supply Wells in

Central Arabia,” paper SPE 36181 presented at the 1996ADIPEC held in Abu Dhabi, October 13-16.

19. Frenier, W.W.:"Acidizing Fluids used to Stimulate HighTemperature Wells Can be inhibited with OrganicChemicals," paper SPE 18468 presented at the 1989 SPEInt. Symposium on Oilfield Chemistry, Houston, TX,February 8-10.

20. Linke, W.F.: “Solubilities of Inorganic and Metal OrganicCompounds”, Ed. A. Seidell, 4th Edition, AmericanChemical Society, Washington, DC, 1958, 1154.

21. Nasr-El-Din, H.A, Al-Humaidan, A.Y., Fadhel, B.A. andSaleh, R.M.: "Effect of Acid Additives on the Efficiencyof Dissolving Iron Sulfide Scale,” Paper # 439, to bepresented in NACE Conference, 2000.

22. Taylor, K.C., Nasr-El-Din, H.A. and Al-Alawi, M.: “FieldTest Measures Amount and Type of Iron in Spent Acids”,paper SPE 50780 presented at the 1999 SPE InternationalSymposium on Oilfield Chemistry held in Houston, TX,February 16-19.

SPE 58712 INVESTIGATION OF SULFIDE SCAVENGERS IN WELL ACIDIZING FLUIDS 7

Table 1: List of Additives

Additive Designation Chemical Type

Aldehyde A Aliphatic aldehyde solution

Aldehyde B Aliphatic aldehyde solution

Aldehyde C Aliphatic aldehyde solution

Aldehyde D Aromatic aldehyde solution

Formaldehyde 37 wt% formaldehyde

Inhibitor A Acetylenic alcohol/phenyl vinyl ketone

Inhibitor B Acetylenic alcohol/aromatic quat

Inhibitor C Aromatic quat /aromatic aldehyde

Formic acid Aqueous formic acid

Surfactant A Nonionic Surfactant A

Surfactant B Nonionic Surfactant B

Table 2: Corrosion Inhibition of L-80 Steels in 7.5 wt% HCl Acid SystemsTest: 150 °F - 4 hr - FeS (tech):HCl ratio: 3:200

InhibitorLoading

Inh-B

H2S ControlAld-A or B Ald-D

Additives Pit(PI)*

Corrosion Rate(lb/ft2)

0.2% Ald. A 3.0% -- -- 0 0.002

0.2% Ald. B 3.0% -- -- 0 0.0050.2% Ald. A 2.75% 0.25% 0.5% Surf-A

+1.0% NTA

0 0.001

0.2% Ald. B 2.75% 0.25% 0.5% Surf-A+

1.0% NTA

0 0.004

0.2% Ald. B 3.0% -- 0.5% Surf-A+

1.0% NTA

0 0.02

* PI = pitting index. PI ≤ 3 is acceptable

8 H.A. NASR-EL-DIN ET AL. SPE 58712

Table 3: Corrosion Inhibition of L-80 Steels in 7.5 wt% HCl Acid SystemsTest: 275 °F - 4 hr - 5,000 psi

FeS (tech):HCl ratio: 1.2:100

Inhibitor Loading Inh-B Formic Acid

H2S Control Ald-A/B Ald-D

Additives Pit(PI)*

Corrosion Rate(lb/ft2)

1.0% 2.0% 2.0% A 0.2% Surf- A (0.5%)+

NTA (35 ppt)

3 0.019

1.0% 2.0% 2.0% A 0.2% Surf-B (0.5%)+

NTA (35 ppt)

2 0.028

0.6% 2.0% 2.0% A 0.2% Surf-A (0.3%)+

NTA (35 ppt)

2 0.009

1.0% 2.0% 2.0% B 0.2% Surf-A (0.5%)+

NTA (35 ppt)

3 0.035

0.6% 2.0% 2.0% A none Surf-A (0.3%)NTA (35 ppt)

1 0.083

0.6% 2.0% 2.0% B 0.2% Surf-A (0.3%)NTA (35 ppt)

2 0.028

0.6% 2.0% 2.0% B none Surf-A (0.3%)+

NTA (35 ppt)

1 0.054

* PI = pitting index. PI ≤ 3 is acceptable

ppt: lbs additive per thousand gallons of acid

Table 4: FeS Dissolution in 7.5 wt% HCl Inhibited with 1.0% Inh. B + 2.0% Formic AcidTest: 275 °F- 4 hr - FeS (tech):HCl ratio: 1.2:100

Additives Iron Analyses Sulfur Analysis

Scavenger Ald-D Others

Total [Fe] [Fe] due Corrosion Equiv. FeS dissolved(1) [S] conc. In acid Equiv. FeS dissolved(2)

ppm (g Fe) (g Fe) (g FeS) (% theo.) (% S) (g FeS) (% FeS)

Ald-B(2.0%)

0.2% Surf-A (0.5%)NTA (35 ppt)

9600 1.51 0.438 1.07 89.4% 0.426 1.16811 108.9%

Ald-B(2.0%)

0.2% Surf-A (0.3%)NTA (35 ppt)

8700 1.37 0.3786 0.99 82.6% 0.398 1.09133 110.1%

Ald-A(2.0%)

0.2% Surf-A (0.3%)NTA (35 ppt)

5590 0.88 0.2072 0.67 56.1% 0.342 0.93778 139.4%

Ald-B(2.0%)

0.2% Surf-B (0.5%)NTA (35 ppt)

13080 2.06 0.6663 1.39 116.0% 0.483 1.32441 95.1%

(1) Equivalent FeS dissolved based on iron analyses.(2) Equivalent FeS dissolved based on H2S generated and determined by sulfur analyses

SPE 58712 INVESTIGATION OF SULFIDE SCAVENGERS IN WELL ACIDIZING FLUIDS 9

Table 5: FeS Dissolution in 7.5% HCl Inhibited with 0.6% Inh-B + 2.0% Formic AcidTest: 275°F- 4 hr - FeS (tech):HCl ratio: 1.2:100

Additives Iron Analyses Sulfur Analysis

Scavenger Ald-D Others

Total [Fe] [Fe] dueCorrosion

Equiv. FeS dissolved (1) [S] conc in acid Equiv. FeS dissolved (2)

ppm (g Fe) (g Fe) (g FeS) (% theo.) (% S) (g FeS) (% FeS)

Ald-B (2.0%) None Surf-A(0.3%)

16900 2.66 1.0945 1.57 130.5% 0.498 1.36554 87.2%

Ald-A (2.0%) None Surf-A(0.3%)

12440 1.96 0.6587 1.30 108.3% 0.346 0.94875 73.0%

Ald-A (2.0%) None Surf-A(0.3%)

12400 1.95 0.6587 1.29 107.8% 0.342 0.93778 72.5%

(1) Equivalent FeS dissolved based on iron analyses. (2) Equivalent FeS dissolved based on H2S generated and determined by sulfur analyses.

Table 6: Formula of the acid used in the pickle treatment.

Material Concentration, gals/1000 gals of acid

Low sulfate content water 349Raw acid (31 wt%) 612Corrosion Inhibitor B 6Corrosion Inhibitor Aid 20Surfactant 3Aldehyde B 20Aldehyde D 2

10 H.A. NASR-EL-DIN ET AL. SPE 58712

Table 7: Chemical analysis a of well return samples after the pickle treatment

Time,Minutes

pH HCl,% wt/v

Sulfide Na Ca Mg Cl SO4 Fe (III Fe (II

0 2.2 0.03 130 217 142 48 808 305 28.2 408 2.2 0.03 110 218 140 48 789 301 23.2 5316 2.3 0.03 140 212 140 47 734 306 20.9 3524 2.1 0.121 190 214 143 47 976 300 28.5 4332 2 0.07 110 209 138 46 1130 293 29.8 5540 1.8 0.11 140 210 141 47 14900 296 37.7 4548 1.7 0.14 160 213 142 48 1740 292 41 4856 1.4 0.29 140 210 140 47 3140 294 48.7 5064 1 0.69 160 221 145 49 6690 278 73.3 5872 0.6 1.58 190 215 155 55 145000 428 104 12080 < 0.1 11.4 210 164 99 34 106000 258 532 58088 < 0.1 NA b 210 119 65 22 183000 171 682 750

96 < 0.1 19.33 190 111 58 20 186000 148 972 1060102 < 0.1 18.72 190 117 68 21 NA 168 2160 2490106 < 0.1 18.69 190 115 64 21 183000 181 3910 4800

a. All ion concentrations are expressed in mg/L.b. Not available.

SPE 58712 INVESTIGATION OF SULFIDE SCAVENGERS IN WELL ACIDIZING FLUIDS 11

Figure 1: Sulfide Reaction Tester at 150 oF

Stirrer

Reaction Flask

Heating Mantelwith Controller

Dropping Funnel

Gas Trap

Figure 2: Efficiency of Capturing H2S and Dissolving of FeS Using HMTA.

0

20

40

60

80

100

0.0 2.0 4.0 6.0 8.0 10.0

Initial Scavenger Concentration, wt%

Eff

icie

ncy

, %

Dissolution of FeS

Capturing of H2S

12 H.A. NASR-EL-DIN ET AL. SPE 58712

Figure 3: Acid Concentration in the Supernatant - HMTA.

Figure 4: Efficiency of Capturing H2S and Dissolving FeS - Aldehyde-B.

0

20

40

60

80

100

0 2 4 6 8 10

Initial Scavenger Concentration, wt%

Eff

icie

ncy

, %

Capturing of H2S

Dissolution of FeS

0

2

4

6

8

0 2 4 6 8 1 0

In it ia l S c a v e n g e r C o n c e n t ra t io n , w t%

HC

l Co

nce

ntr

atio

n, %

wt/

v

SPE 58712 INVESTIGATION OF SULFIDE SCAVENGERS IN WELL ACIDIZING FLUIDS 13

Figure 5: Acid Concentration in the Supernatant - Aldehyde-B.

Figure 6: Efficiency of Capturing H2S in the Presence of Formaldehyde, Aldehyde-B, HMTA, Aldehyde-A.

0

2

4

6

8

0.0 2.0 4.0 6.0 8.0 10.0

In i t ia l Scavenger Concentrat ion, w t%

HC

l Co

nce

ntr

atio

n, %

wt/

v

0

20

40

60

80

100

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0

Initial Scavenger Concentration, wt%

Eff

icie

ncy

of

Cap

turi

ng

H2S

, %

FormaldehydeAldehyde-BHMTAAldehyde-A

14 H.A. NASR-EL-DIN ET AL. SPE 58712

Figure 7: Efficiency of Dissolving Iron Sulfide in the Presence of Formaldehyde, Aldehyde-B, HMTA, Aldehyde-A.

0

10

20

30

40

50

60

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0

Initial Scavenger Concentration, wt%

FeS

Dis

solv

ed, %

Formaldehyde

Aldehyde-BHMTA

Aldehyde-A

SPE 58712 INVESTIGATION OF SULFIDE SCAVENGERS IN WELL ACIDIZING FLUIDS 15

Figure 8: Dissolution of FeS in HCl at 150 °F

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

Wt.%

Control

16 g Ald. A

0.2% Inh. B

15 g Ald. A

/1 g Ald. D

16 g Ald. B

16 g Ald. B

/0.2% Inh B

5 g HMTA

2.16 mL A

ld. D

10 g Ald. C

9 g 37% form

aldehyde

Additive

FeS Dissolved, %

H2S Evolved, %

10 g FeS, 108 g HCl

Figure 9: Dissolution of FeS in 7.5 wt% HCl at 150 °F

0.10

1.00

10.00

100.00

Wt.%

Control

16 g

Ald

. A

0.2%

Inh. B

15 g

Ald

. A/1

g A

ld. D

16 g

Ald

. B

16 g

Ald

. B/0.

2% In

h B

5 g H

MTA

2.16 m

L Ald

. D

10 g

Ald

. C

9 g 37

% fo

rmald

ehyd

e

Additive

FeS Dissolved, %[S] in Acid, %

10 g FeS, 108 g Acid

16 H.A. NASR-EL-DIN ET AL. SPE 58712

Figure 10: Dissolution of FeS in 7.5 wt% HCl at 150 °F

0.00

0.00

0.01

0.10

1.00

10.00

100.00

Wt. %

6g A

ld. A

6g A

ld. A

+ In

h. A

6 g A

ld. B

6 g A

ld. B

+ In

h A

5 g A

ld. A

5 g A

ld. A

+ 1

g A

ld. D

.

5.5 g

Ald

. A/In

h. D/A

ld. B

5.5 A

ld. B

/Inh. B

/Ald

. D

5.5 A

ld. B

/Inh. B

5.5 A

ld. B

/Inh. C

.

Additive

% Dissolved

H2S Evolved, %

3 g FeS, 200 g Acid