I SPE 38795 Society of Petroleum Engineers Reservoir Souring: Analysis of Surveys and Experience in Sour Waterfloods Z. |. Khatib, SPE, Shell Development Co., and J.P. Salanitro, Shell Development Co. Conroe 197, Soety Palm Ene ‘is pape mas pre fr point 1907 SHE Rul Teri Cones a ‘ia ppur na ete! for rsaison Wy an SPE Prgar Cormie toning eof norman cones an tect bid Dy he autor). Cats ot pera ‘esr, have tt Den rove by he Sat ef Panam Engrs ae ae Sac rect ha ashore} Te alr peed, eo ht nesmny rfl aftr tne Suey ct Pavinen goer, te coum, x acinsPapee peered at SPE ‘maine ar je option low by Eslrl Carmo ot Saat of Parum Egneas Carte repetition btn, ngs oan pa al he pape eee pore meu th when conn of 0 Sosty of Fatman Engrs prohotes. menor to repacuon pat = vested To an saat of 2 mere tar 0 nrc ‘Mortons my rt be sop Tw aera mat cin conupnn sender twee ‘dy oan paper me ponria Wil rar SPE, PO, Box 03895 Pan, os Seas USA, Pan, ONE IEEE Abstract ‘Mechanisms of reservoir souring are reviewed in general. A survey was conducted on several seawater and source-water floods to determine the factors that could be responsible for reservoir souring. Data from Shell's offsbore Gulf of Mexico field (Cognac Platform) were analyzed more closely, and the results are presented as a case history. All seawater floods ‘examined in the survey were found to be soured to varying degrees. The main factors responsible forthe souring of seawater floods appear to be the sulfate ion concentration, the organic acid Content, and the salinity of the produced water. The role of sulfate-reducing bacteria in souring of several Shell waterfloods is discussed. Introduction Many offshore fields require pressure maintenance in order to recover oil and gas reserves. Often there are no source-water sands available, and seawater is the only available injection ‘water. Formation souring with the injection of relatively low salinity and high sulfate content brines, such as seawater, has been observed at some time during the producing life ofthe field ‘The number of sour wells within a field is variable; some wells ‘are noticeably sour (up to 100 ppm of HS in the produced gas), ‘hile others remain free of HS. This souring is generally attributed to sulfate-reducing bacteria (SRB) activity. It is difficult to keep any injection system sterile as well as maintain bacteria-free operations during well drilling and completion ‘The main goals of this investigation were 1. Toinitiate an industry survey of seawater floods in the Gulf of Mexico, Alaska, and California, ‘To identify factors that could cause formation souring, ‘To develop a methodology to predict the likelihood and ‘magnitude of HaS generation, and ‘To outline the field and research studies necessary to ‘understand reservoir souring mechanisms. Incentives to understand reservoir souring include () predictions that would impact the facilities and downhole tubing design and material selection and, perhaps, the ol value of future deepwater developments, and (2) knowledge on how to control, chemically or biologically, the extent of sour gas production in sweet reservoirs for reducing potential equipment ‘and pipe corrosion failures, formation plugging, and environmental and human health hazards. Goals 1,2, and were. achieved. However, ue tothe limited data, the development of ‘method to predict the magnitude of HS generation was not possible ‘This paper presents the current understanding of reservoir souring mechanisms and an analysis of survey data that were ‘compiled on seawater floods and selected source-water floods Data from SOY's Cognac flood were reviewed more closely, and the results are presented as a case history. A general review of field experience on the role of SRB in souring Shell waterfloods is also presented. MECHANISMS OF RESERVOIR SOURING ‘The following section is a summary of the current proposed mechanisms of reservoir souring. ‘The microbial and abiotic ‘Reochemical mechanisms are discussed, 1. Microbial sulfate ion (S07) or sulfur (S) reduction. It 4s well known that the SRB are a physiologically diverse and ‘ubiquitous group of anaerobic bacteria capable of reducing SO; to HxS when grown on several “oxygen-containing” substrates such as short-chain volatile acids (formic, acetic, propionic, and ‘butyric, lactic acid, phenols, and benzoates.'* Volatile fatty acids are present in many oilfield produced waters,? and they may ‘be a predominant factor in the growth of sulfate-reducers in oil reservoirs and the sour gas formation during waterflooding for enhanced recovery. More recent evidence in the literature indicates that SRB can be isolated from oilfield produced waters and oil-water separators, marine sediments, and aquifer soils, 4492 ESERVOIR SOURING: ANALYSIS OF SHELL'S SURVEYS AND EXPERIENCE IN SOUR WATERFLOODS: which can utilize the sleum hydrocarbons, hexadecane,* and toluene and xylene Although many of the SRB species isolated from produced waters grow optimally at 95°F {G0-35°C), there have been several reports on the isolation of thermophilic SRB from producing wells of oil reservoirs that have produced sour gas from previously sweet formations.”® Thermophilic (130°F, 55°C) and extremely thermophilic (185°F, 85°C) sulfate-reducers have also been isolated from geothermal and marine hyrdothermal vent systems9!0 In addition, thermophiles have been isolated from submarine thermal springs and solfataras which can grow at temperatures of 170-221°F (77-105°C) and reduce elemental sulfur to H2S in the presence of fatty acids, proteins, and sugars.!!!? Until recently it was not known whether SRB in injection water fuids were capable of migrating through an oilfield reservoir, In 1996 Beeder and others! showed that a specific benzoate-degrading strain of SRB could be transported through a porous rock reservoir from injection to producing wells within a period of three years, 2. Thermochemical sulfate or sulfur reduction by hydrocarbons. Thermochemical $07 reduction by bydro- carbons at high temperatures (570-660°F, 300-350°C) was demonstrated by Toland!* according to the following reaction: HS 30—120min SOz + 1.33(CH,) + 0.66H,0 H,S + 1.3300, + 20H- 11S (or polysulfides) participates as an autocatalyst inthe reaction. Orr repeated these experiments at 347°F (175°C) and obiained a significant conversion (22 percent) of the SO; © HS in 26 days.!5 ‘The proposed mechanisms for sour gas formation in ‘deep carbonate reservoirs involve (a) the formation of sulfur (S) by the reaction of SO} with small amounts of HS associated with the oil or connate water, and (b) the thermal hydrolytic reduction ‘ofS and oil hydrocarbons to form HS. Other studies by Orr,1516 showing that the isotope ratios of sulfur species (oil-organic sulfur, sulfides, and $07) from the Big Hom and Wind River basins (Wyoming) are similar, suggest that this thermochemical sulfur reduction may explain the origin of reduced sulfur ‘compound in crudes. Other findings supporting this reduction of SOV/S in deep carbonate reservoirs are those of Powell and MacQueen!” with bitumen and, more recently, of Krouse and ‘thers! who showed that light hydrocarbon gases (ethane, ‘propane, and butane) may reduce SO, to HS at temperatures of 194-347°F (90-175°C), Laboratory experiments by Belkin and ‘others! have demonstrated that elemental sulfur can be chemically reduced by organic material, e.g, bacteriological culture media components, at = 176°F (80°C), 3. Thermal hydrolysis of organic sulfur. An alternative explanation for the occurrence of HS in produced gases from Canadian carbonate formations has been proposed by Clark and ‘others atthe University of Calgary2°-22 ‘Their steam simulation experiments have shown that thiophene -type compounds found {in heavy crude ols (> 2-5 percent S) can be desulfurized to HS at temperatures 2 392°F (200°C). These reactions were also ‘enhanced with nickel and vanadium metal catalysts and low pH. Its also possible that other sulfide and disulfide compounds in SPE 39795, oils may be similarly decomposed to HzS in the presence of reservoir rock (carbonates, clays). These surfaces may act as catalysts for promoting the hydrolysis. This mechanism of HS. formation, however, does not explain sour gas from reservoirs containing light crudes, e.g, Michigan and Cognac oil fields, ‘with low levels of organic-S compounds ( = 0.5 percent). 4. Hydrolysis of metal sulfides, The association of polymetallic sulfides, €.2, Feros? Soos2, with petroleum deposits was observed by Kvenvolden and others?? in samples from the Gorda Ridge volcanic center off the northern California, coast. Recent studies by Marstand and others? have indicated that metalic sulfides (FeS, FeS2) can hydrolyze under acidic conditions to form HS. Their calculations suggest. that reservoirs containing pyrites could potentially produce significant levels of 1,8 by this mechanism. It is also possible that alkaline earth metal sulfides, e.g, CaS, may be associated with citfrock formations and undergo rapid hydrolysis upon ‘water washing. 5. Desorption of HS from formation sediments Geochemical investigations by Le Tran®S have shown that HS (or polysuifides) can be soluble in petroleum fractions and/or sorbed to formation sediments similar to gaseous hydrocarbons. If o-bearing reservoirs contain significant levels of sorbed H2S, from diagenesis, itis possible that degassing of this trapped H2S could occur when these formations undergo waterflooding. ‘The Role of SRB in Souring of Several Waterfloods: General Field Experionce Studies were conducted during 1982-1988 on the role of SRB in the sour gas production of fresh water and recycled produced waterfloods of Michigan, Ventura, and Califonia and. the seawater floods of Cognac (Gulf of Mexico), Cook Inlet (Alaska), and Huntington Beach, California " Our general observations are that: 1. The microbial origin of sour gas from reservoirs or {njector/producer wellbore zones is not well established, but data from some reservoirs suggest H2S may be of microbial origin when fatty acids (acetate and propionate) are present in formation waters. which are < 5-7% salinity and downhole temperatures are = 100°C. 2. SRB andlor aerobic (facultaively anaerobic) bacteria can be cultured from injection waters, surface treatment facilities (tanks, flow lines, free-water-knockout systems), or produced. ‘waters from wells. These cultures may represent the usual contamination of oil field facilites and equipment with microbes associated with soils, surface waters, muds, drilling fluids, and chemicals. (It is important to note that drilling ‘operations probably have contaminated injectors and producers with muds and soils), 3. Most SRB cultures isolated from field samples grow at 95°F 25°C) in laboratory culture media, while very few, e. ‘Ventura strains, could be isolated which can reduce SO; HS at 130°F (55°C) 4, ‘The presence or absence of culturable SRB in produced ‘waters did not correlate withthe presence of HaS (some well ‘waters contained SRB but were not sour, while others did not contain culturable SRB but were sour).SPE-a8705 Z.J.KHATIB AND J.P. SALANITRO. A 5. Sulfur isotope ratio analysis* (relative abundance of S$ and Laboratory experiments confirm the potential for biofilm 32g) of injection and produced water SO, and HS from sour _growth of SRB on formation rock, internal pipe surfaces and wells and crude oil oganic-sulfur species have indicated that __ perhaps wellbore zones (injectors/ producers) in the presence of some of the 4S values of field gas samples are variable and organic acids nutrients from produced fluids “2-8 However, the ‘appear to be nonmicrobial or may be of microbial or abiotic actual presence of these microbes growing and producing Sour origin (inconclusive). See Table 1. The isotope ratios of gas under reservoir conditions is yet to be verified against other produced sour gases also do not appear to be sufficiently possible mechanisms or in-situ reservoir/wellbore conditions. depleted in 4S when compared with the 6°45 of biologically Geochemical studies by other workers have indicated that these produced HS and metal sulfides from shallow anaerobic may be abiotic mechanisms in which HpS can be formed in an sediments and muds of lakes, rivers, andoceans (see Table 2). _cilfield reservoir. ‘Tablo 1—Variation in 5%S Isotope Ratios Field Flood Water Temp,*F (°C) A= Ventura ‘Seawator/FreshiProd.+Fresh 250 (126) B~Cook Inlet Seawater 156 (69) C-Bront ‘Seawater 212 (100) Michigan Freshwater/Produced 108 (43) E-Cognac Seawater 150 (65) 1H,S torn Themochemical S07 Reduction (»80-120°C) F Huntington Seach — SeawateriProduced 140 (60) —— —___! S07 in Evaporites Measured Values in Produced Water A rn ania aE FoB oD ‘Measured Values in Seawater ‘S07 In Modem Seawator u aaa BEC HS from Microbial S07 Reduction (<80°C) Measured Values in Produced HS i abroana cA BDF Petrcloum Organi Sutur Measured Values in Crude Components a , 40 80 ~10 ° 10 20 30 400 ‘5S (parts por thousand) where R =* S/S. 4514 RESERVOIR SOURING: ANALYSIS OF SHELL'S SURVEYS AND EXPERIENCE IN SOUR WATEAFLOODS. Table 2—Summary of Literature Data on Microbial Sulfur Isotope Fractionation SPE 98705 ‘Samples Sulfur 8S A(so; — H,8) species too) “SE A. Environmental Samples MacNamara and Thode, 195127 African Lakes: SO; +19 36 HS 47 Thode et a., 195428 Texas and Louisiana suifur SO; 438 to+40 43-58 Hes Kaplan and Rittenberg, 196220 California marine sediments so; +20 7 “8 Jensen, 1962 Long island Sound +18 2 anaerobie mud “9 Kaplan otal, 968°" Shallow RedSeasedirents SOT +2 to42¢ 0-57 Ss! 12t039 Krouse et al., 197032 ‘Western Canadian SO; +10 to 425 10-40 springs and sediments Oto=15 Grey and Jensen, 197259 Great Salt Lake sediments: +10 to417 O13 ‘aioe Matrosov eta, 1976 Fussian lekos wih 4906 = ot low sulfate (10-40 ppm) “at0017 high sulfate (200-1300 pom) +10 10421 12-51 “210-00 ‘Sweeney and Kaplan, 198095 Gulf of California deep water ND 2 and sodimonts (closed system) ‘Schidlowski et al., 1983°° Gulf of California sediments +20 17-60 ssto-40 B. Laboratory Culture Experiments ones and Starkey, 195757 D. desulturieans ; 12 680% $0; reduced (28°C) HS 4240-1119 4-18% SO, reduced (9-18°C) oS 17 10-23 19-25 Kaplan and Rittenberg, 1964°° O. desulturicans (nongrowing) reducing $0, (0-20°C) HS -St0-48 3.46 reducing SO; (5-35°C) HS — 0to-14 ond Chambers a al, 19759 D. desutureans, 30°C HS 1710-95. 17435 (low growth rato ~6% SO; utized) McCready, 19754 ‘Low growth rate cultures {0.118% of $0; utiized) Desutovibro sp!(22-80°C) aS -Sto~12, S12 Desufotomaculumep.(90-55°C) HS —Ato-t1, 1 Effect of lactate concentration (800-3200 ppm) ‘HS. =3to-10 310 Effect of SO; concenvation sHaS-_—-BtOWI2_ GH. Effect of SO; concentration *HyS_—St0-B esting suspension Desulfovibrio (30°C) HS 17 to-21 17-21 Desutfotomaculum (55°C) HS -Bto-12. GH Fry et al, 198847 D. vulgaris (20-25°C) HS 60-9 69 (pure or mixed cutures) Herbert and Gilbert, 196742 Desutovibro sp. SO; sst048 (6 strains, 30°C, lactate) 10, 25% soawater HeS +6 to+7 ° 50, 90% seawater HS 440010 Strain SPWD(20°O; acetatelpropionate) 10, 25% soawater HS 48 tovit ° 50, 90% seawater HS -titonzs 17-92 452‘SPE'36705, Reservoir Souring Survey ‘A survey was conducted of various seawater and source-water floods, The survey sheets contained information regarding injection and production water chemical compositions, chemical treatment of source water, production histories temperature and pressure of reservoirs, descriptions of H§ histories, and field ‘operating problems. ‘Waterflood data from Shell Offsbore GOM waterfloods and Shell Westem EAP in Alaska and California were compiled in this survey. For comparison purposes, data from North Sea and other locations were included in the analysis. Table 3 lists the ‘contents ofthe data base by type of waterflood. Table 3—List of Fields Included in Survey Data Base Field Name: Waterfood Formation Location ‘Tyee Cognse: ‘Geewaler Sandstone Gulfol Mexico Huntington Beach Seawater Sandstone Catfomia Eugene sland 175 Seawater Sandstone Gulf of Mexico ‘Kuperuk River® ‘Seawater Sandstone Alaske-NorthSlops Prudhoe Bay ‘Soawaler Sandstone Alaska-NorthSlope Cook Inet ‘Seawaler Sandstone Alaska-Cook net Brent ‘Seawater Sandetone Nort Sea Main Pass 6 Source Sandstone Coastal Loulsana Bay MarchandST:2e Source Sandstone Gulf of Mexico Ventura FreshProcuced Sandstone Calfomia Bota ‘Souree/Produced Sandetone Calfomia Chester 18 ‘Souree/Produced Carbonate Michigan Presentation of Survey Results ‘The injection and production water chemistry, the bottombole temperatures, and the cumulative water production have been mown to cause the souring of waterfloods. These parameters hhave been considered in the analysis of the available data base. Z|. KHATIBAND J.P. SALANITRO. Correlation of HS with Produced Water Chemistry. Several factors that may contribute to waterflood souring were reviewed. ‘These included the SO;, the organic acid levels, and the chloride ‘concentrations of the injected and produced water. ‘Table 4 lists the concentrations ofthese factors for twelve fields. Relation of Sulfate Tonto HS Presence. The effect of SO; concentration on H2S presence in twelve fields is shown in Figure 1, Two fields were injected with source wate, three were flooded with blends of sourcesfresh and produced, and the remainder were flooded with seawater. The results indicated that the presence of the SO; in the injected water always corresponded with the detection of HS. Al seawater floods have tumed sour. Fields flooded with blends of source and produced ‘water (containing sulfate) have also tumed sour, while those that ‘were kept on source water with no sulfate ion present bave not produced any detectable HS, Eos BeEEEC OEE some ap 42: one atch Coenen Pend Cn pe Fig. 1—Influence of sultate lon on H,S concentration. Table 4—A List of Factors That Could Cause Hz Production in Sweet Reservoirs Sop $0; ‘Temperature Temperature HySMax Log (HS) (Produced Water) (Injocted Water) (Producer) (Infact) TOSx1- Fatty Acide (ppm) (mg) (mol) (CF) F(a) (mg) Bay MarhandST26 064 0.19 4 1 220 = 12 = Main Passo - - 6 4 175 175 109 710 Bota - = 100 = 160 150 at “ Eugene island 175 8 0.90 1475 2060 180 180 m 5 Brent 2 148 33 2020 173 173 8 aaa Ventura 50 170 2 3 150 150 10 728 Cognac st wm 315 3245, 160 180 9 190 Chester 18 100 200 900 900 108 109 102 2 Cook inat 200 230 135 1350 185 155 19 ze Kuparuk 00 278 85 2200 182 70 v = Prudhoe Bay 1100 3.04 sit 2570 200 5 2 5 Huntington Beach 40000 460 250 2100 ns 120 2 5 4536 RESERVOIR SOURING: ANALYSIS OF SHELL'S SURVEYS AND EXPERIENCE IN SOUR WATERFLOODS. SPE 20795, Relation of Total Dissolved Solids to HyS. The maximum HS level in the produced gas was ploted.as a function of the otal dissolved solids (TDS) in the produced water (Figure 2). The results suggest that there is a range of TDS (20,000-30,000 mg/) where the H2S concentration apparently peaks and then decreases when the TDS approaches 100,000 mg/l. An exception to this trend is Michigan Chester 18 Field (TDS = 182,000 mg’. ‘This field, a carbonate reservoir, may have soured due to the {intrusion of sour gas from the Detroit River Basin or due to HS inclusions as a result of a geochemical mechanism, a scurce water Gatens a seowoter 105 5 19m recent Water g/L Fig. 2—Influence of total dissolved solide on HaS concentration. Relation of Organic Acids Level to H,S. The fatty acids in the produced water for the surveyed fields are presented in Figure 3. The results indicate that fields which have soured ‘contain both fatty acids and sulfate ions in the produced water. ‘No souring occurred in fields that were flooded with sulfate- deficient water even though fatty acids were present in the ‘produced water, Ventura souring isan exception. This field may have soured due to injection of dissolved HzS generated by SRB con surface facilities as indicated by the low HS concentration in the gas (1.2 ppm). More data on fatty acids are required before establishing conclusions on the presence of formation fatty acids as a growth source for SRBs and sour fields, Folly bit Cnc, a/h. Fig, 3 tauence of fatiy aclée in produced water on HS ‘concentration. Correlation of HS with Bottomhole Temperatures, The H2S evel in twelve fields was plotted as a function of the bottorahole temperature in producers (Figure 4). ‘There is no apparent ‘correlation between H,S generation and temperature, Seawater- flooded fields with temperatures up to 200°F (93°C) have soured. Fig. 4—Influence of bottomhole temperature on H;S concentration, Discussion of Survay Results from Cognac Fiold “The data from the Cognac Field were reviewed closely, and the ‘effects of an increase in water-cut and salinity of the produced ‘water on the degree of HS production are presented in the following sections. Effect of Water-Cut on HS Concentrations. Investigators‘? have shown that, with an increase in water-cut and a decrease in 8-oil ratio, the HS concentration will increase exponentially. ‘The measured HS concentration in the produced gas and the calculated concentration per unit of produced water* are plotted as a function of cumulative water production for well A-SI Figure 5). ‘The results indicate that HyS increases initially but levels off quickly, and then decreases with more water production. Obviously, the correlation between HS and the ‘water-cut is not clear, although one could deduce that itis due to the increased fraction of seawater rather than to actual water-cut Plugging of the most permeable zones, for example with BaSO, scale, would affect the water-cot values. ‘In Figure 6, the HS concentration in the gas was plotied as a function of cumulative water production for several wells. The results indicate no obvious correlation with the cumulative water produced. The H2S concentration peaked at $0 ppm in two wells. (Gvell A-51 and well A-49) and at 15 ppm in the other two wells. (well A-39 and well A-45), imrespective of the cumulative water production, ‘The main apparent difference between these sets of ‘wells was the erratic change in the chloride concentration (i.e. fraction of seawater) of the produced water with further production "mg of HaSMiter of produced water = ppm in gas x density of gas x gas/water ratioSPE 36705 Z.LKATIB ANO J.P SALANITRO a ergs Enfect of Salinity of Produced Water on H2S Concentrations a i The HoS content in produced gas, the HpS concentration per unit A pee poe ose 20s mn HS / et tae i HyS Concentration 50100 =~«180~=«200 Cumulative Water Production, Mb Fig. 5—Effect of cumulative produced water on H;S concentration. AAS ee HS Concentration, ppm 160 320 Cumulative Water Production, Mbb| 640 800 Fig. 6—influence of water production on H;S content in the ga, Cognae producers 455 of produced water, and the sulfate ion concentrations were plotted as a function of the chloride concentration for several Cognac producers. ‘The results are presented in Figures 7, 8, and 9. These data suggest the following 1. There appears to be a range of chloride concentrations where the HS concentration is maximum, The data show that, in ‘general, the range occurs between 25,000 and 35,000 mg/l. This range may be favorable for the production of H2S via the SRB mechanism, since it could provide the required amounts of the ‘SO; and the organic acids. 2. Wells which have shown a decrease in chloride concentration from that of formation water (= 45,000 mg/l) to that of seawater (=22,000 mg/l) have shown an initial increase in the H2S concentration to about 20 ppm and then a sustained decrease in HyS to less than 1 ppm (Figure 7). 3. Wells which had an initial dilution with seawater and then, at a later stage, were invaded with formation water have shown an erratic increase in the HS concentration (almost double that of the previous wells) Figure 8). This change in the mixing ratio of seawater to formation water in the produced fluids was observed following the conversion of several downdip producers to injectors t0 produce downdip banked oil. Similar observations were cited* for wells in the North Cormorant Blocks I, 1, and TV seawater floods. HS produced from several wells (up to25 mg HzS/ in produced water) was noted in Blocks 1 and ITT but notin wells from Block IV (up to 1.6 mg H2S/lin total ‘uids). ‘This was attributed to the possible connection between ‘upper reservoir production and production in Blocks I and III only, after these zones were swept with seawater. In other words, the commingling of the high seawater content in the produced ‘water occurred with the formation water from other layers in Blocks I and I 4, Wells which have undergone a complete conversion {from produced water (a blend of seawater and formation water) to formation water showed a significant decrease in HS concentrations (Figure 9). '. The concentrations of HyS per unit of water produced (mgf), although much lower than the concentration in the produced gas due to the stripping effect of the gas, displayed similar trends to salinity changes. 6. The changes in HS concentration correlate well with the $07 concentration in the produced water (sce Figures 7, 8, and 9). A decrease in SO; concentration appears to correspond to a decrease in HS concentration,2 RESERVOIR SOURING: ANALYSIS OF SHELL'S SURVEYS AND EXPERIENCE IN SOUR WATERFLOODS [SPE 99795 50 50 - Ae ppmin produced gas te ppmin produced gas ; 40> (mgt. x10) of produced water .” acl 5 : sot £30 5 3 3 % 8 2 . 4 = ob ° 30 20 30 40 30 Chloride Concentration x 10°, mg/L ‘Chloride Concentration x 10-8, mg/L 3000 2000 S 270 1800 E 2400 ? ‘1600 ‘§ 2100 be 8 1000 $200 § 1500 1000 8 = 1200 > 5 ms ae E600 § r g 3S sot 200 N gm ° Oo 4 27 30 33 36 30 12 45 8 = so 0 8 ood 6 8 Chioride Concentration x 10°, mgA. CChoride Concentration x 10-2, mg/L Fig. 7—The HS and eullala ion concentrations as auction ofthe FI9-8The HS and wallet on concentrations ae a functon ofthe chloride concentration inthe produced water of well A-39, ehleride concentration in the produced water of well A-49, 456SPE ‘36705 10 “A ppmin produced gas He mglL of produced water Hz Concentration 30 40 Chloride Concentration x 10-%, mg/L 50670 30 Chloride Concentration x 10-8, mg/L 4 50 60. 70 Fig. 9The H,S and sulfate fon concentrations as a function of the ‘*hloride concentration in the produced water of well A-7D. Economic Impact of the Reservoir Souring Problem Recent MMS (Mineral Management Services) regulations (CFR 250) clearly state that provisions must be made inthe well design ifthe anticipated HS exceeds the NACE limit of 0.05 psia. (HS range in the gas would be 7 t0 20 ppm depending on gas pressure). Therefore, the production casing should be designed accordingly. ‘The cost of upgrading the production tubing, packers, gas lift mandrels, landing nipples, etc, is anticipated to be in the hundreds of thousands of dollars per well. If the surface-controlled subsurface safety valve (SCSSV) is included, the material upgrade to alloy 718 would cost tens of thousands of dollars per well. The upgrade in design to utilize API 14A Cass II certified valves would add tens of thousands of dollars to the cost. AS a result, the project has an additional burden that could be in millions of dolar. Tension leg production platforms will most likely require Jong, large-diameter, corrosion-resistant tubing strings capable of handling high rates of production. This application could be 2.1. KHATIB AND J.P. SALANITRO 487 ‘met with a 22Cr material in a 3.5-inch, 9.3-I6/ft tubing string. ‘The 22Cr material is resistant to a partial pressure of only 0.3 psi HS, which limits its application to exposures of about 45 ppm HQS. Upgrading the wibing string to Sanicro 28 would double the cost of a string, Conclusions The conclusions of our study are based on trends rather than ‘quantitative values, since the accuracy of the data cannot be determined and the quantity of data was very limited. The following general conclusions can be made: 1. All seawater floods examined inthis study have soured. to varying degrees. New seawater flood projects should be designed for sour service. 2. The factors that are responsible for souring of seawater floods appear to be the sulfate ion concentration, the organie acid level (acetate and propionate), and the salinity of the produced water. 3. ‘The tend for souring was strongly dependent on the ‘presence of sulfate ion in the injected water. Fields in the Gulf of ‘Mexico that were flooded with source water devoid of sulfate hhave not soured (e.g.. Bay Marchand ST-26). Fields that were flooded with blends of produced water (containing sulfate) and source water have produced HS, e., Ventura and Chester 18, Michigan. 4, The survey indicated thatthe sour fields can be grouped into two categories: those that exhibit low levels of H2S in the ‘produced gas, typically below SO ppm, and those that have HS levels greater than 100 ppm. We speculate thatthe source of HoS, ‘n the first category could be bacteria related, whereas the source ‘of the second category may involve more than one of the reservoir souring mechanisms presented. 5. The HoS concentration in the produced gas increases initially with an increase in water production but generally levels off after a few months of water production. In some wells, the HAS level was observed to decrease when the salinity of the produced water approached that of seawater. 6. There appears to be a relationship between the mixing ratio of formation and injected seawater and the magnitude of HES levels. Data from Cognac suggest that levels of HS in the produced gas generally leveled off at 20 ppm as the flood matured. However, upon conversion of several producers to ‘injectors and the resultant commingling of the unflooded formation water with injected seawater, the level of HS appeared to double Recommendations ‘The results of our survey are considered a step towards ‘understanding the reservoir souring phenomenon. However, there isa need for verifying the significance ofthe factors which ‘caused the HS production, particularly for identifying the time of occurrence, mechanism, and the degree of souring. Furthermore, the inability to determine an upper limit on the concentration of HS from the available data requires more ‘comprehensive survey. ‘The following sections outline our recommendations for the field and research studies that would enhance our knowledge in predicting reservoir souring and ways to alleviate this problem.1. Analyses of HS concentration in injector’s flowback fluids to determine whether reservoir souring is initiated in the injector vicinity and propagated towards the producer with the seawater front. The data can be collected from all sour waterfloods, 2. Analyses if H2S concentrations in the produced fluids from infill producers to identify ifthe reservoir is entirely sour or if HS formation is due to the contamination of the near-wellbore ‘one of producers 3. Analyses of the formation rock for the existence of any 1Hy$-scavenging minerals or the presence of pyrites. Review of core data or core flow studies should also be performed for all sour waterfloods. 4. Analyses of produced fluids from all sour waterfloods for organic acids to identify their significance in the survival of SRB. 5. Analyses of downhole injected and produced fluids for SRB. ‘The use of the reverse osmosis membrane technology is for sulfate removal from seawater on a large scale. This technology ‘has been shown to be effective in reducing the reservoir souring ‘and potential scale deposition problems in the North Sea and in the Gulf of Mexico on Marathon’s platforms.4®-5! The “Seaject” hydrogen process used for oxygen scavenging would be recommended as an altemative to the sulfite-based oxygen scavengers to prevent addition of any sulfite to the system, Research Studies. A comprehensive laboratory investigation is recommended 1. To identify factors which may affect the growth of SRB ‘under reservoir conditions (temperature, pressure, salinity, reservoir rock composition, and formation water organics) 2. To determine" maximum — acceptable sulfate concentrations in injection water that would prevent souring 5? 3. To investigate altemate mechanisms of souring, e.g, catalytic sulfate reduction by trace minerals in reservoir rock. Emphasis would be at lower temperatures such as in wells of the Chester 18 Field (109°F, 43°C). 4. To determine if the sulfur content in the crude contributes to souring in waterfloods. References 1, Postgate, J.R: The Sulphate-Reducing Bacteria, Cambridge University Press, Cambridge, England (1979) 8-23. 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