抗H2S腐蚀碳钢材料

新型抗H2S/CO2腐蚀高温缓蚀剂研制【摘要】通过对咪唑啉中间体的改性，合成了一种具有较好耐高温（150℃）和耐h2s/co2高酸性能的含氟咪唑啉类缓蚀剂，其合成条件为：咪唑啉中间体、特种含氟表面活性剂摩尔1∶0.6，反应温度为50℃，反应时间为24h。

实验结果表明常压下在150℃、对7.78%硫化氢，7.00%二氧化碳，84.5%的甲烷；0.74%乙烷的混合气体，当缓蚀剂的加量为0.08%（wt%），缓蚀率可以达到92.9%。

其在碳钢表面的吸附遵循langmuir吸附等温式。

【关键词】高温缓蚀剂 h2s/co2腐蚀咪唑啉氟类特种表明活性剂1 引言在h2s/co2腐蚀防护中，使用缓蚀剂是是经济有效的一种抗腐蚀方法。

其具有用量小、设备简易、防腐效果好等优点。

目前，国外各油田所使用的缓蚀剂中，吸咪唑啉缓蚀剂及其衍生物的用量大于90%。

故咪唑啉分子可以通过其五元环上的两个氮原子与金属表面铁原子键合，而咪唑啉分子上的疏水基团在金属表面外侧排列开，将介质与金属表面分开，使得h3o+难以接近金属，从而大大减低了金属的腐蚀速率，达到防腐的目的。

而且咪唑啉类缓蚀剂具有低毒、高稳定性等优点，在工业酸洗、油气田等领域的防腐过程中具有非常广阔的应用前景。

所以，国内外咪唑啉的复配与改性研究已经成为了缓蚀剂研制的一个热点。

目前咪唑啉类缓蚀剂在低温下对h2s/co2有很好的防腐作用，但在高温下由于其水解而使得其作用效率大大降低。

本文基于前人研究对对咪唑啉不同中间体效果缓释研究的基础上上，合成了一种新的含氟咪唑啉类缓蚀剂，该剂具有耐高温（150℃）与高酸性气体的特点。

2 含氟咪唑啉缓蚀剂的合成2.1 实验仪器及药品实验药品主要有氯化钾、氨水、氢氧化钠、冰乙酸、正辛酸、二乙烯三胺、二甲苯、三乙胺、特种表面活性剂、石油醚无、水乙醇。

实验器材有电热恒温水浴锅、增力电动搅拌器红外光谱仪电子分析天平扫描电子显微镜。

2.2 中间体合成与确认2.2.1？中间体合成对于咪唑啉中间体大量学着做了研究得出了成熟较为相同的合成方法：以二甲苯作为携水剂即酸与多胺脱水进行的氨解反应生成酰胺；随后升高温度进一步脱水，通过环化过程得到咪唑啉缓蚀剂的中间体。

例谈L360QB抗硫碳钢管道辽河油田双6区块气驱采油开发工程井场部分是辽河储气库建设的重要组成部分，气田有机硫含量较高，介质条件非常苛刻。

该系统大量使用了L360QB 抗硫碳钢管道。

本文以该项目天然气主输送管道为例，详细介绍该类抗硫化氢碳钢管道的焊接，为以后同类工程的焊接施工提供经验。

1 L360QB抗硫碳钢管道简介L360QB抗硫碳钢管道为气田地面集输工程的主输送管道，其C、S、P等杂质元素含量比较低，可焊性好；在强度等级上属于X52级别，屈服强度不小于360 MPa，抗拉强度不小于460 MPa。

2 L360QB管道的可焊接性分析L360QB管道是按GB50540-2009《石油天然气站内工艺管道工程施工规范》生产的抗硫化氢碳钢管道，该管道杂质元素控制非常严格，交货状态为形变热处理。

该类管道中的S、P等有害元素含量非常低，P≤0.010%，S≤0.002%，Mn/S≈720。

在研究这类钢的可焊性以后发现，此类钢碳当量低，可焊性好，冷裂倾向小；由于S、P等有害元素含量控制得非常严格.所以热裂倾向小；同时，由于其Mn/S≈720，在数值上非常高，焊接热影响区液化裂纹敏感性非常低；而且，由于其杂质含量控制严格，再热裂纹敏感元素含量低，焊接完成以后，焊缝金属中产生再热裂纹及层状撕裂等焊接缺陷的机会非常小。

总之，此类钢是一种可焊性非常好的钢。

3 L360QB管道焊接接头耐蚀性试验3.1 焊接接头耐蚀试件的取样加载应力（1）焊接接头耐蚀试件的取样GB50540-2009《石油天然气站内工艺管道工程施工规范》中关于HIC和SSC 的评价标准，主要是针对于管材和板材，没有专门焊接接头的取样规范，为此，查阅了大量文献，在大量试验经验的基础上，结合对相关规范的理解，确定了焊接接头的取样标准。

焊接接头的Hlc试样应垂直于焊缝取样，且焊缝应位于试件的中心线上，在整个圆周上等距120。

取3个试样，取样部位和试验后试样的切取和检查位置如图1所示。

硫化氢腐蚀的机理及影响因素作者：安全管理网来源：安全管理网1. H2S腐蚀机理自20世纪50年代以来，含有H2S气体的油气田中，钢在H2S介质中的腐蚀破坏现象即被看成开发过程中的重大安全隐患，各国学者为此进行了大量的研究工作。

虽然现已普遍承认H2S不仅对钢材具有很强的腐蚀性，而且H2S本身还是一种很强的渗氢介质，H2S腐蚀破裂是由氢引起的；但是，关于H2S促进渗氢过程的机制，氢在钢中存在的状态、运行过程以及氢脆本质等至今看法仍不统一。

关于这方面的文献资料虽然不少，但以假说推论占多，而真正的试验依据却仍显不足。

因此，在开发含H2S酸性油气田过程中，为了防止H2S腐蚀，了解H2S腐蚀的基本机理是非常必要的。

(1) 硫化氢电化学腐蚀过程硫化氢(H2S)的相对分子质量为34.08，密度为1.539kg/m3。

硫化氢在水中的溶解度随着温度升高而降低。

在760mmHg，30℃时，硫化氢在水中的饱和浓度大约3580mg/L。

在油气工业中，含H2S溶液中钢材的各种腐蚀(包括硫化氢腐蚀、应力腐蚀开裂、氢致开裂)已引起了足够重视，并展开了众多的研究。

其中包括Armstrong和Henderson对电极反应分两步进行的理论描述；Keddamt等提出的H2S04中铁溶解的反应模型；Bai和Conway对一种产物到另一种产物进行的还原反应机理进行了系统的研究。

研究表明，阳极反应是铁作为离子铁进入溶液的，而阴极反应，特别是无氧环境中的阴极反应是源于H2S中的H+的还原反应。

总的腐蚀速率随着pH的降低而增加，这归于金属表面硫化铁活性的不同而产生。

Sardisco，Wright和Greco研究了30℃时H2S-C02-H20系统中碳钢的腐蚀，结果表明，在H2S分压低于0.1Pa时，金属表面会形成包括FeS2，FeS，Fe1-X S在内的具有保护性的硫化物膜。

然而，当H2S分压介于0.1～4Pa时，会形成以Fe1-X S为主的包括FeS，FeS2在内的非保护性膜。

H2S、CO2的腐蚀机理H2S 环境中⾦属抗硫化物应⼒开裂和应⼒腐蚀开裂的室内试验NACE Standard TM0177‐2005Item No.212121总则2试剂及试验溶液3测试试样及材料性能5⾼温/压⼒条件下试验6试验⽅法A‐NACE标准拉伸试验7试验⽅法B‐NACE标准弯曲试验8试验⽅法C‐NACE标准C‐环试验1、总则1.1本标准涵盖了在含H2S的低pH值⽔溶液中，遭受拉伸应⼒的⾦属材料抗开裂失效的试验。

碳钢和低合⾦钢通常在室温下测试EC抗⼒，在这个温度条件下，它们的SSC敏感性是较⾼的。

对于其它类型的合⾦来说，EC敏感性和温度的关系更加复杂。

1.2本标准描述了试剂、检测样品和所⽤设备，讨论了基本材料和测试试样的性能，接着说明了试验步骤。

本标准介绍了4种试验⽅法：试验⽅法A-NACE标准拉伸试验试验⽅法B-NACE标准弯曲试验试验⽅法C-NACE标准C-环试验试验⽅法D-NACE标准双悬臂梁（DCB）试验本标准的第1⾄5部分给出了⽤于4种试验⽅法总的评论。

第6⾄19部分说明了每⼀种试样的试验⽅法。

表明了检测每种样品所需要的检测⽅法。

在每⼀种试验⽅法开始描述之前，给出有助于判定该试验⽅法适⽤性的总的指导⽅针（6-9 部分）。

实验结果报告也被讨论到。

1、总则1.3可在温度和压⼒下对⾦属进⾏抗EC试验，温度和压⼒可以是室温的（⼤⽓条件的），或⾼温压⼒条件的。

1.4 该标准可被⽤作接受或拒绝试验，来保证产品达到EC 抗⼒的某种最低⽔平，这由API说明5CT，ISO11960指定，或由使⽤者或购买者指定。

为了研究或提供信息的⽬的，该标准可提供产品EC抗⼒的定量测量。

试验⽅法A 在720⼩时内，最⾼⾮失效应⼒。

试验⽅法B 在720⼩时内，对50％失效概率，统计基础上的临界应⼒因⼦（SC）。

试验⽅法C 在720⼩时内，最⾼⾮失效应⼒。

试验⽅法D 对有效试验来说，重复测试试样的平均KISSC （SSC门槛应⼒强度系数）。

1、下列环境发生湿H2S腐蚀开裂：（1）含游离水；（2）以下四个条件之一：（i）游离水中H2S溶解量大于50ppmw；（ii）游离水pH值小于4，且有溶解的H2S存在；（iii）游离水pH值大于7.6，水中溶解的HCN大于20ppmw，且有溶解的H2S存在；（iv） H2S在气相中的分压大于0.0003MPa。

2、特别是当设备和管道的介质环境符合以下任何一条时称为湿H2S严重腐蚀环境：（1）液相游离水的pH值大于7.8，且在游离水中的H2S大于2000ppm；（2）液相游离水的pH值小于5，且在游离水中的H2S大于50ppm；（3）液相游离水中存在HCN或氢氰酸化合物，且大于20ppm。

二、设计、制造要求1、设备和管道如选用碳素钢或低合金钢，必须是镇静钢；2、对湿H2S腐蚀环境下的碳素钢或低合金钢制设备和管线，材料的使用状态应是正火、正火+回火或调质状态；3、材料的碳当量CE应不大于0.43（CE=C+Mn/6+(Cr+Mo+V)/5+(Ni+Cu)/15；式中各元素符号是指该元素在钢材中含量百分比）；4、在湿H2S严重腐蚀环境下，当材料的抗拉强度大于480MPa时要控制其S含量不大于0.002%，P含量不大于0.008%，Mn含量不大于1.30%，且应进行抗HIC性能试验或恒负荷拉伸试验。

5、在湿H2S环境下，应尽量少选择焊接。

如采取焊接，原则上应进行焊后消除应力热处理，热处理温度应按标准要求取上限。

6、热处理后碳素钢或碳锰钢焊接接头的硬度应不大于HB200，其它低合金钢母材和焊接接头的硬度应不大于HB237；7、热加工成形的碳素钢或低合金钢制管道元件，成形后应进行恢复力学性能热处理，且其硬度不大于HB225；8、冷加工成形的碳素钢或低合金钢制设备和管道元件，当冷变形量大于5%时，成形后应进行消除应力热处理，且其硬度不大于HB200。

但对于冷变形量不大于15%且硬度不大于HB190时，可不进行消除应力热处理；9、接触湿硫化氢环境碳素钢螺栓的硬度应不大于HB200，合金钢螺栓的硬度应不大于HB225；10、铬钼钢制设备和管道热处理后母材和焊接接头的硬度应不大于HB225（1Cr-0.5Mo、1.25Cr-0.5Mo）、HB235（2.25Cr-1Mo、5Cr-1Mo）和HB248（9Cr-1Mo）；11、铁素体不锈钢、马氏体不锈钢和奥氏体不锈钢的母材和焊接接头的硬度应不大于HRC22，其中奥氏体不锈钢的碳含量不大于0.10%，且经过固溶处理或稳定化处理；12、双相不锈钢的母材和焊接接头的硬度应不大于HRC28，其铁素体含量应在35-65%的范围内；13、容器内在焊接接头两侧50mm范围内的表面进行防护，可在表面喷锌、喷铝并用非金属涂料封闭的方法；14、不使用承插焊形式的管件；15、结构上应尽量避免应力集中；16、设备壳体或卷制管道用钢板厚度大于12mm时，应按JB/T4730进行超声波检测，符合Ⅱ级要求。

09Cr2AlMoRe与08Cr2AlMo综合性能比较一、概述12Cr2AlMoV钢材经工业化应用，证明在低温H2S-HCI-H2O系统、低温H2S-HCN-H2O系统以及低温H2S-HCN-CO2-H2O系统中，与碳钢和一般不锈钢相比，具有更优异的抗应力腐蚀性能。

12Cr2AlMoV主要利用铬、铝、钥的综合抗腐蚀能力增加其整体抗腐蚀效果，同时钢中添加一定的钒(0.05%~0.15%)，以增加其钢材的机械性能，细化和强化钢中的晶粒，固溶碳分子的析出，进一步改善和增强12Cr2AlMoV的抗腐蚀能力。

但其焊接性能差，冷弯硬度高，不利于换热器管束的制造和使用。

另外，由于12Cr2AlMoV钢种研制完成后只能在原上钢三厂生产板材，其使用范围受到了较大的限制。

在这种情况下，江阴兴澄钢管有限公司在抗H2S应力腐蚀用钢12Cr2AlMoV 基础上开发了新钢种08Cr2AlMo，它保留了12Cr2AlMoV耐腐蚀性能，去掉了钢中的V元素，改善了焊接性能，于1999年初研制成功并投放中石化应用。

1999年8月获得了由全国压力容器标准化技术委员会、国家技术监督局颁发的技术评审证书，2000年度获国家新产品奖，2001年9月通过中石化《换热器用防腐蚀新钢种08Cr2AlMo的开发研制应用》技术鉴定，2001年12月获冶金产品实物质量金杯奖。

另外，湖北长江石化和深圳润之达科技开发有限公司合作，也是在抗H2S应力腐蚀用钢12Cr2AlMoV基础上开发了新钢种09Cr2AlMoRe，它在去掉12Cr2AlMoV 中的钒以后对其化学成分进行了重组，用性能极好的稀土(RE)元素代替钒(V)。

稀土(RE)元素具有钒(V)元素在钢中的所有优点：即细化晶粒、对其它化学元素起固溶作用。

同时，稀土在炼钢中还能起脱氧和脱硫的作用，钢材在通过精炼后硫(S)的杂质含量能够进一步降低，提高了钢材抗湿H2S应力腐蚀开裂的能力。

另外，在Fe-Cr-AI合金中添加稀土，提高了钢的强度、塑性、韧性、耐蚀性及抗氧化性，同时亦改善了焊接性能，其可焊性较好。

油气田开发过程中，腐蚀现象非常普遍，由此造成的损失也是非常之大，尤其是硫化氢应力腐蚀，它是在没有任何先兆、硫化氢浓度较低、工作人员难以发现的情况下就可以发生，特别是对于一些强度较高的钢材而言，即使在正常的载荷下，没有明显的腐蚀迹象，就可能发生硫化氢脆性开裂，可见，硫化氢脆性开裂的危害性与防腐的紧迫性。

对于硫化氢含量较高的油气田而言，这种腐蚀尤为严重。

在我国油气田开发过程中，曾发生过许多硫化氢氢脆和应力开裂事故，比如四川龙会2井井喷、渡1井井喷；川西北7井，钻具氢脆断裂，直接损失100万元[1]；威远气田23井（H2S含量为1.2%），N80套管加固焊缝发生脆裂，导致井喷44天；较为典型的如卧龙河气田卧31井（H2S量为9.55%），C-75套管由于冷变形致使硫化物应力开裂而脆断[2]；2003年四川罗家寨气田井喷，硫化氢介质造成百余人伤亡；2005年中原油田输油管道因未作防腐处理，导致四个月后，管线多处穿孔，被迫更换管道[3]。

鉴于硫化氢对油气井腐蚀造成的巨大损失，开展油气田防腐技术研究与开发具有实用价值的防腐技术已迫在眉睫。

1　硫化氢对油气用钢腐蚀机理与腐蚀类型1.1　腐蚀机理钢材在含H2S的酸性水溶液中受到电化学腐蚀，阴极和阳极均有反应，整个电化学反应过程至少有下面三个阶段：H2S电离：H2S→HS-+H+阳极反应：Fe+HS-→FeS+H++2e-阴极反应：2H++2e-→2H→H2（一部分H原子会渗透到碳钢中）钢材在含硫化氢的水溶液中的应力腐蚀，主要是阴极反应析出的氢原子向钢材内部扩散，而被金属内部缺陷处或空隙处所形成的隐阱捕集，继而结合成氢分子，在钢材内部产生巨大的内应力，使钢材脆化或开裂，其特征是属于低应力的破坏，开裂的断口无塑性变形，呈脆性破坏，俗称氢脆。

1.2　腐蚀类型硫化氢应力腐蚀是当硫化氢腐蚀钢材时，在阴极区产生大量的氢原子，氢原子渗透到钢材内部结合成氢分子而导致的硫化氢应力腐蚀。

湿H2S腐蚀破裂的试验方法11、前言在石油生产中有很多设备都暴露在富含H2S的环境中，这些设备用碳钢制作，在湿H2S 中容易腐蚀破裂。

NACE(美国腐蚀工程师协会)开发了耐湿H2S破裂的材料要求和评价材料耐H2S破裂试验方法方面的标准。

开发硫化物应力破裂（SSC）、氢至破裂（HIC）和应力定向氢至破裂（SOHIC）试验方法是出于评价和评定材料在含硫环境中使用的工业需要。

NACE TM0177‘在H2S环境中金属耐特定形式环境性破裂的实验室试验’[1]是开发用于评价耐SSC的，而另一个NACE标准TM0284[2]则是开发用于评价管道和压力容器钢耐HIC性能的。

在NACE TM0284中规定的方法已经成功地用于评价化学成分、组织、材料加工和取向对耐HIC的作用。

为了研究SOHIC，在ASTM G-39[3]中所述的双梁试样结构已经用于研究拉应力下的焊接件和母体钢材。

2、试验方法所研究的试验方法已经用于开发用于含硫环境中使用的改良合金和特定含硫环境应用的材料选择中。

影响破裂行为的因素包括合金成分和显微组织、硬度、总应力（施加应力+残余应力）和诸如PH值和腐蚀性等环境参数。

举例说，图1示出了两种材料（AISI4130低合金钢和12%Cr不锈钢）在出现SSC的临界应力下的硬度的影响[4]。

表1列出了原来由Cotton开发后来写入NACE TM0284的在一个湿H2S环境中研究HIC的实验室试验方法—‘BP试验’的试验条件。

图1：低合金钢（AISI4130）和不锈钢（AISI410）的SSC门槛值对比无缝管和焊管的试样位置和取向如图2所示，母材和焊缝金属试块的尺寸均为20x100mmx壁厚，每种材料将3件不施加应力的试样浸没在H2S饱和溶液中。

试验之后，将每件试块按如图3所示分成3个剖面抛光，用100x放大倍率的光学显微镜作HIC检查。

通过以下3个比值定量评价HIC，结果如图4所示：1原著：M.Elboujdaini，CANMET材料试验室，加拿大。

日期：抗硫化氢腐蚀用SA-333 Gr.6(HIC)无缝钢管供货技术条件1、适用范围本技术条件适用于在酸性环境下使用的SA-333 Gr.6(HIC)钢管的检验与验收。

2、技术要求 2.1化学成份钢的化学成分（wt%）应符合表1的规定。

表1钢管的化学成分 wt%（1）表中未注明元素符合SA-333 Gr.6的规定。

（2）碳当量（CE ）计算公式如下：CE=C+Mn/6+(Cr+Mo+V)/5+(Ni+Cu)/15CE ＜0.43%； （3）2.2力学性能力学性能应符合表2的规定表2力学性能2.3交货状态:正火2.4钢管的布氏硬度值≤210HB 。

2.5钢管尺寸、外形、重量及允许偏差应符合ASME SA-999／SA-999M 的规定。

2.6钢管标志及质量证明书应符合ASME SA-999／SA-999M 的规定。

2.7钢管应进行水压试验或NDE 检测。

2.8 水压试验应符合ASME SA-999／SA-999M 的规定。

2.9钢管无损检测应符合ASME E213或SA-E309的规定。

3.附加要求3.1. 主体材料应提供EN 10204 3.1证书。

3.2．按UG-84进行-46℃低温冲击，冲击功均值为27J ，单个不小于213.3．钢管抗氢致裂纹（HIC）试验检验规则抗氢致裂纹（HIC）试验方法，执行NACE TM0284标准，采用A溶液，三个试样平均值为：CLR≤10%；CSR≤1%；CTR≤3%。

其中PH:介质酸碱度；CLR：裂纹长度百分比；CSR：裂纹敏感百分比；CTR：裂纹厚度百分比。

湿硫化氢环境腐蚀与防护第一章总则1.1 为规范湿硫化氢环境腐蚀与防护工作，防止发生安全事故，依据国家有关法规、标准，制定本指导意见。

1.2石油化工装置在湿硫化氢环境（含有气相或溶解在液相水中，不论是否有氢气存在的酸性工艺环境）使用的静设备，为抵抗硫化物应力腐蚀开裂（SSC）、氢诱导开裂（HIC）和应力导向氢诱导开裂（SOHIC），在设计、材料、试验、制造、检验等方面的要求。

生产、技术、设计、工程、检修、科研等部门应积极参与和配合设备管理部门做好相关工作。

1.3对处于湿硫化氢腐蚀环境中的设备抗 SSC、HIC/SWC 和 SOHIC 损伤的最低要求，其中包括碳钢和低合金钢，以及碳钢及低合金钢加不锈钢的复合钢板制造的设备。

但不包括采用在金属表面（接触介质侧）增加涂层（如喷铝等）防止基体材料腐蚀开裂的设备。

1.4凡处于湿硫化氢环境中的设备在材料选择、设备制造与检验均应满足本标准的要求，否则可能导致设备 SSC、HIC/SWC 和 SOHIC 的破坏。

1.5不包括湿硫化氢引起的电化学失重腐蚀和其他类型的开裂。

1.7 湿硫化氢腐蚀环境的定义与分类：1.7.1 介质在液相中存在游离水，且具备下列条件之一时称为湿硫化氢腐蚀环境：（1）在液相水中总硫化物含量大于 50ppmw；或（2）液相水中 PH 小于 4 且总硫化物含量大于等于 1ppmw；或（3）液相水中 PH 大于 7.6 及氢氰酸（HCN）大于等于 20ppmw，且总硫化物含量大于等于 1ppmw；或（4）气相中含有硫化氢分压大于 0.0003MPa（0.05psia）。

1.7.2 根据湿硫化氢腐蚀环境引起碳钢和低合金钢材料开裂的严重程度以及对设备安全性影响的大小，把湿硫化氢腐蚀环境分为 2 类，在第I 类环境中主要关注 SSC，而在第Ⅱ类环境中，除关注 SSC 外，还要关注HIC 和 SOHIC 等损伤。

具体划分类别如下：第 I 类环境（1）操作介质温度≤ 120℃；（2）游离水中硫化氢含量大于 50ppmw；或（3）游离水的 PH ＜ 4，且含有少量的硫化氢；或（4）气相中硫化氢分压大于 0.0003MPa（绝压）；或（5）游离水中含有少量硫化氢，溶解的 HCN 小于 20ppmw，且 PH ＞7.6。

加氢类装置腐蚀与防护摘要：随着经济的不断发展，能源消耗不断增加。

能源劣质化也是越来越严重，从而导致原油中含有硫、含酸的成分不断提升，从加重了腐蚀。

在柴油加氢装置工作中，具有高压高温特性，所以非常容易受到一些物质的腐蚀。

另外在柴油加氢装置在反应过程中，会产生一些H2S，所生产的H2S会对柴油加氢装置设备的安全运行产生一定的危害。

为了更好的保证柴油加氢装置的安全稳定运行，必须对柴油加氢装置采取一定措施，降低所生产的腐蚀情况，更好的保证柴油加氢装置的安全稳定运行。

关键词：加氢装置；腐蚀；防护措施1加氢装置的主要类型加氢装置按加工目的可分为：加氢精制、加氢裂化、渣油加氢处理等类型，这里主要介绍加氢裂化装置。

加氢裂化按工艺流程可分为：一段加氢裂化流程、二段加氢裂化流程、串联加氢裂化流程。

一段加氢裂化流程是指只有一个加氢反应器，原料的加氢精制和加氢裂化在一个反应器内进行。

该流程的特点是：工艺流程简单，但对原料的适应性及产品的分布有一定限制。

二段加氢裂化流程是指有两个加氢反应器，第一个加氢反应器装加氢精制催化剂，第二个加氢反应器装加氢裂化催化剂，两段加氢形成两个独立的加氢体系，该流程的特点是：对原料的适应性强，操作灵活性较大，产品分布可调节性较大，但是，该工艺的流程复杂，投资及操作费用较高。

串联加氢裂化流程也是分为加氢精制和加氢裂化两个反应器，但两个反应器串联连接，为一套加氢系统。

串联加氢裂化流程既具有二段加氢裂化流程比较灵活的特点，又具有一段加氢裂化流程比较简单的特点，该流程具有明显优势。

2设备腐蚀情况2.1高温氢腐蚀氢气在常温下对普通碳钢没有腐蚀，但是在高温、高压下则会产生腐蚀，使材料的机械强度和塑性降低。

高温氢腐蚀的机理为氢气与材料中的碳反应生成甲烷，使材料的机械强度和塑性降低，形成的甲烷在钢材的晶间积聚，使材料产生很大的内应力或产生鼓泡、裂纹。

至于在什么条件下产生腐蚀，则根据Nels。

n曲线确定。

为避免高温氢腐蚀，加氢装置高温、高压、临氢部分的设备、管线多采用合金钢或不锈钢。

Electrochimica Acta 56 (2011) 1752–1760Contents lists available at ScienceDirectElectrochimicaActaj o u r n a l h o m e p a g e :w w w.e l s e v i e r.c o m /l o c a t e /e l e c t a c taEffect of H 2S on the CO 2corrosion of carbon steel in acidic solutionsYoon-Seok Choi a ,∗,Srdjan Nesic a ,Shiun Ling ba Institute for Corrosion and Multiphase Technology,Department of Chemical and Biomolecular Engineering,Ohio University,342West State Street,Athens,OH 45701,USA bExxonMobil Research and Engineering Company,1545Route 22East,Annandale,NJ 08801,USAa r t i c l e i n f o Article history:Received 30June 2010Received in revised form 13August 2010Accepted 14August 2010Available online 20 August 2010Keywords:CO 2/H 2S corrosion Carbon steel Iron sulfide Acid solutions Precipitationa b s t r a c tThe objective of this study is to evaluate the effect of low-level hydrogen sulfide (H 2S)on carbon diox-ide (CO 2)corrosion of carbon steel in acidic solutions,and to investigate the mechanism of iron sulfide scale formation in CO 2/H 2S environments.Corrosion tests were conducted using 1018carbon steel in 1wt.%NaCl solution (25◦C)at pH of 3and 4,and under atmospheric pressure.The test solution was saturated with flowing gases that change with increasing time from CO 2(stage 1)to CO 2/100ppm H 2S (stage 2)and back to CO 2(stage 3).Corrosion rate and behavior were investigated using linear polar-ization resistance (LPR)technique.Electrochemical impedance spectroscopy (EIS)and potentiodynamic tests were performed at the end of each stage.The morphology and compositions of surface corrosion products were analyzed using scanning electron microscopy (SEM)/energy dispersive spectroscopy (EDS)and X-ray photoelectron spectroscopy (XPS).The results showed that the addition of 100ppm H 2S to CO 2induced rapid reduction in the corrosion rate at both pHs 3and 4.This H 2S inhibition effect is attributed to the formation of thin FeS film (tarnish)on the steel surface that suppressed the anodic dissolution reaction.The study results suggested that the precipitation of iron sulfide as well as iron carbonate film is possible in the acidic solutions due to the local supersaturation in regions immediately above the steel surface,and these films provide corrosion protection in the acidic solutions.© 2010 Elsevier Ltd. All rights reserved.1.IntroductionThe number of sour (CO 2+H 2S containing)oil and gas fields being produced worldwide is increasing,as sweet (CO 2contain-ing)fields are being depleted,and higher oil prices made it possible for profitable development of sour oil and gas fields.A concern in the production and transportation sour oil and gas is the corro-sion caused by the acid gases CO 2and H 2S.Even though corrosion resistant alloys (CRA)has long been available as a material selec-tion option that mitigates CO 2and H 2S corrosion,carbon steel is in general more cost-effective for oil and gas facilities and hence,is the most widely used material option [1].The internal corrosion of carbon steel pipeline in the presence of CO 2and H 2S was firstly recognized in the 1940s and has been investigated for over 60years [2].Several studies have shown that the presence of H 2S could either cause an acceleration or an inhibition of the corrosion of carbon steel,depending on the partial pressure of H 2S.It was reported from early studies that at H 2S concentrations below 690Pa,a pro-tective iron sulfide film formed.At H 2S concentrations greater than 690Pa,a non-protective film formed [3–5].More recently,Ma et al.∗Corresponding author.Tel.:+17405939944.E-mail address:choiy@ (Y.-S.Choi).claimed that H 2S provides a strong inhibition under certain special conditions that have lower H 2S concentration (≤0.04mmol dm −3),pH value of 3–5,and longer immersion time (≥2h)[6].Abelev et al.also reported that 5ppm of H 2S concentration have an inhibiting effect on corrosion in the presence of CO 2[7].Even though there is no absolute criterion for the H 2S concentration that provides inhi-bition,it has been suggested that the inhibition effect is related to the formation of iron sulfide with different crystal structures,such as amorphous ferrous sulfide,mackinawite,cubic ferrous sulfide,smythite,greigite,pyrrhotite,troilite,and pyrite [8–12].However,there is no clear understanding of the nature of the surface layer formed in CO 2/H 2S environments as well as their pro-tective properties in acidic solutions when the concentration of H 2S is too low to cause a concern of the surface layer cracking or blis-tering.The objective of this study is to evaluate the effect of very low-level H 2S on CO 2corrosion of carbon steel in acidic solutions,and to investigate the mechanism of the iron sulfide layer formation in CO 2/H 2S environments.2.ExperimentalThe specimens were made of carbon steel (AISI C1018)that has a chemical composition of 0.21%C,0.05%Mn,0.09%P,0.05%S,0.38%Si and balance Fe.The specimen shape was of a cylindrical geom-etry,1.3cm in diameter and 1.3cm in height,and would have its0013-4686/$–see front matter © 2010 Elsevier Ltd. All rights reserved.doi:10.1016/j.electacta.2010.08.049Y.-S.Choi et al./Electrochimica Acta56 (2011) 1752–17601753Fig.1.Schematics of the test apparatus.outer surface exposed to solution during testing.The specimen sur-face was grounded to a600gritfinish using silicon carbide paper, then cleaned with isopropyl alcohol in an ultrasonic bath and dried.The corrosion tests were carried out in a2L glass cell which con-tained a rotating cylinder working electrode,a reference electrode consisted of a glass capillary probe connected to a saturated Ag/AgCl electrode,and a platinum wire counter electrode.The schematic of this experimental setup is shown in Fig.1.All the tests were conducted in1wt.%NaCl solutions at room temperature and atmo-spheric pressure.Gas mass-flow controllers were used to control theflow rates of CO2and H2S to the test cell,as well as to obtain the desired H2S concentration.These gases were mixed byflowing through a mixer before injecting into the test cell.Before specimen was inserted into the solution,the solution was purged with CO2for 2h in order to deoxygenate,then with pH adjusted to the desired value by adding a deoxygenated HCl solution or NaHCO3solution as appropriate.Table1shows the test conditions,and Fig.2shows the experi-mental procedures.This test procedure was designed to investigate the effect of H2S on the corrosion of carbon steel in CO2envi-ronments;the environment was changed from CO2(stage1)to CO2/100ppm H2S(stage2)and then back to CO2(stage3).During experiment,instantaneous corrosion rates were monitored with linear polarization resistance(LPR)measurements made at regular time ing the polarization resistance(R p)obtained from LPR measurements,the corrosion current density(j corr)was calcu-lated using Eq.(1)[13],and the resulting j corr yields the corrosion rate using Eq.(2)[14]:j corr=BR p=ˇaסc2.3×R p×(ˇa+ˇc)(1)corrosion rate(mm/year)=0.00327×j corr(␮A/cm2)×EWdensity(g/cm3)(2)Table1Test conditions.Parameter DescriptionMaterial C1018carbon steelRotation speed1000rpmSolution Deionized water with1wt.%NaCl Temperature25◦CTotal pressure0.1MPaCO2partial pressure0.097MPaH2S concentration100ppm(0.01kPa)pH3,4whereˇa is the anodic Tafel constant,ˇc is the cathodic Tafel con-stant,0.00327is a constant factor used for dimension and time conversion factor,and EW is the equivalent weight in grams.In the present study,different B values were applied to each stage.For CO2environments(stages1and3),0.026V was used as B value, whereas0.013V was used for CO2/H2S environment(stage2).The experimental procedures shown in Fig.2were to have electrochemical impedance spectroscopy(EIS)measurements and potentiodynamic scan performed at the end of each stage.There was,however,the concern that the potentiodynamic scan may cause irreversible alterations to the sample surface(especially the anodic scan)which could render the subsequent testing question-able.Consequently,the actual study consisted of three separate tests;each had only one potentiodynamic scan performed at the very end of the test.In other words,each of these tests had started from the very beginning shown in Fig.2,and had run to the end of stages1,2and3,respectively,when a potentiodynamic scan was performed that concluded the respective test.LPR measurements were performed in a range of±10mV with respect to the corrosion potential,and a scan rate of0.166mV/s.EIS measurements were conducted in the frequency range from10kHz and10mHz,with an AC signal amplitude of10mV(rms)at the cor-rosion potential.The potentiodynamic scans were carried out after the completion of the EIS measurements,and was conducted in the following manner.The scan wasfirst conducted in the cathodic direction from the open-circuit potential(OCP)to−1.2V vs.sat. Ag/AgCl,with a scan rate of0.166mV/s.The OCP was then allowed to return to its previous value,which would occur within about 20min.Then the scan was conducted in the anodic direction from OCP to−0.4V vs.sat.Ag/AgCl,with a scan rate of0.166mV/s.After the experiment,the specimen was used for additional ex situ analyses.The morphology and compositions of corrosion products from each stage were analyzed with scanning electron microscopy(SEM),energy dispersive X-ray spectroscopy(EDS)and X-ray photoelectron spectroscopy(XPS).3.Results3.1.Effect of H2S addition/removal in CO2environment at pH4The results of OCP and LPR measurements at pH4are sum-marized in Fig.3.At the transition from stage1to stage2, when100ppm H2S was added into the CO2environment,the OCP increased and the corrosion rate decreased immediately.This phe-nomenon is probably related to the formation of protective iron sulfidefilm on the steel surface.At the end of stage3,at which point H2S was completely removed from the CO2environment, the OCP and the corrosion rate returned their previous levels in stage1,which suggest the dissolution of the iron sulfidefilm and re-exposure of the bare steel surface to the environment.Fig.4shows the Nyquist plots measured at the end of each stage.All impedance spectra showed a depressed capacitive loop at high frequencies indicating a double-layer capacitance,as well as an inductive loop at low frequencies.Depressed semi-circles are not uncommon for iron dissolution in acidic media and it had been suggested in the literature that this behavior might be related to a heterogeneous surface roughness and the nonuniform distribu-tion of current density on the surface[15,16].In addition,no mass transfer controlled impedance was observed under these condi-tions.However,it was not a pure charge transfer controlled process either because the inductive loop at low frequencies[17]indi-cated that the iron dissolution mechanism might occur in two or more steps involving an adsorbed intermediate[18,19].As Fig.4 shows,the diameter of the semi-circle increased with the addi-tion of H2S indicating a decreased corrosion rate,which suggests1754Y.-S.Choi et al./Electrochimica Acta56 (2011) 1752–1760Fig.2.Experimental procedure for electrochemical corrosion study in pHs 3and 4.the H 2S induced inhibition against the CO 2corrosion of carbon steel.When H 2S was removed from the system,the diameter of the semi-circle decreased indicating an increased corrosion rate,which is consistent with the occurrence of the dissolution of iron sulfide film.It is further noted that the shape of these Nyquist plots (capacitive loop +inductive loop)did not change with the addition and removal of H 2S,indicating the same mechanism for the steel corrosion throughout the entire test,from stage 1to stage 3.The polarization curves of carbon steel obtained at the end of each stage at pH 4were also consistent with the understanding that the inhibition effect of H 2S on CO 2corrosion of carbon steel was due to the formation of a protective film of iron sulfides (Fig.5).As can be seen in Fig.5,the addition of H 2S reduced the anodic current from the iron dissolution reaction,whereas,the cathodic current and hence the cathodic reactions were much less affected.This observation is consistent with existing understanding that many types of iron sulfides are electronic conductors [20],and hence a surface coverage of iron sulfide film may impede the movement of dissolved iron through the film,but not the movement of electrons through the film to continue the cathodic paring the curves from stage 1and stage 2in Fig.5,it can be seen that the OCP increase and corrosion rate decrease in the stage 2curve (also shown in Fig.3)were mostly the results of a change in the anodic paring the anodic polarization curves from stage 2and stage 3,it is suggested that in stage 2environment with protective film formed by H 2S addition,the film is sufficiently stage to inhibit the anodic dissolution reaction at the lower anodic overpotential,but may be damaged by higher overpotential resulting in the stage 2anodic curve to eventually approach that of stage 3one at highoverpotential.Fig.3.OCP and corrosion rate of carbon steel tested at pH4.Fig.4.Nyquist plots of carbon steel tested at pH 4,taken at the end of eachstage.Fig.5.Polarization curves of carbon steel tested at pH 4,taken at the end of each stage.Y.-S.Choi et al./Electrochimica Acta56 (2011) 1752–17601755Fig.6.SEM surface morphologies of carbon steel tested at pH4,at the end of:(a) stage1(CO2),(b)stage2(CO2/H2S),(c)stage3(CO2).The SEM morphologies of the surface of steel specimens col-lected at the end of each stage are shown in Fig.6.No significant difference was observed in the surface morphology from stage1to stage3,which all showed indications that the active dissolution of iron was occurring from within the grains.In addition,EDS analysis showed that only Fe and C were detected on these steel surface(the EDS spectra are not shown).3.2.Effect of H2S addition/removal in CO2environment at pH3Fig.7summarized the results of OCP and LPR measurements at pH3.Here the corrosion rate showed immediate decrease at the addition of100ppm H2S into the CO2environment,followed by further,gradual decreasing throughout stage2.ThiscorrosionFig.7.OCP and corrosion rate of carbon steel tested at pH3.rate behavior is similar to that previously observed at pH4.The OCP,however,followed a very different trend from that observed at pH4.It decreased immediately at the addition of H2S,followed by gradual increasing throughout stage2.It is noted that,in stage 2,the gradual increase of OCP coupled with a gradual decrease of corrosion rate is may be explained by the notion of an inhibition of the anodic dissolution reaction by the formation of an iron sulfide film.Examining stages3in Figs.3and7,it is interesting to note that the trend of corrosion rate after removing H2S from the envi-ronments was different between these two cases at pHs3and4, respectively.Here,at pH3,the corrosion rate did not increase to restore itself to a level similar to the previous stage1.Instead,it further decreased slightly,and then remained at a low but con-stant value throughout the remainder of the test,even though in the same time period the OCP was decreasing continuously withtime.Fig.8.Nyquist plots of carbon steel tested at pH3,taken at the end of each stage.1756Y.-S.Choi et al./Electrochimica Acta56 (2011) 1752–1760Fig.9.Polarization curves of carbon steel tested at pH3taken at the end of each stage.Fig.8shows the Nyquist plots measured at the end of each stage. The impedance spectra at end of stage1and stage2showed a depressed capacitive loop at high frequencies as well as an induc-tive loop at low frequencies,whereas that at end of stage3showed the capacitive loop without the inductive loop.This indicates that the corrosion mechanism in stage3is different from that in stage 1and stage2.In addition,as can be seen in Fig.8,the diameter of the Nyquist plot increased with the addition of H2S,which implies corrosion inhibition due to the formation of iron sulfide on the steel surface similar to that observed in the test at pH4.The Nyquist plot diameter,however,further increased in stage3even though H2S was removed from the system.This observation suggested a fur-ther increase of corrosion inhibition into stage3,but it was unclear whether the inhibition was on the anodic or cathodic reactions.Fig.9shows the polarization curves measured at the end of each stage in the test at pH3.By comparing the stage1and stage2polar-ization curves,it can be seen that the addition of H2S suppressed the anodic reactions,and suppressed the cathodic reactions in the lower overpotential ranges.In stage3,when H2S was removed from the system,the anodic current was further reduced,whereas the cathodic current was not affected.This implies that the increase in the diameter of Nyquist plot at stage3is related to the inhibition of the anodic reaction.In addition,this reduction in the anodic reac-tion is only effective at the lower overpotential range,indicating the formation of protective layer even at stage3.Fig.10shows the SEM observed morphologies of the steel sur-face at the end of each stage.No significant difference was observed in these the corroded surfaces,similar to that found in the case of pH4test.Additionally,EDS analysis found that only Fe and C were detected on these steel surfaces from the EDS analysis(the EDS spectra are not shown).4.DiscussionFig.11shows a comparison of carbon steel corrosion rates mea-sured at the end of each stage in pHs3and4conditions.At pH4, it can be seen from Fig.11that the addition of low concentration of H2S(100ppm)into the CO2environment reduced the corrosion rate,but this inhibition effect disappeared when H2S was removed from the system.However,at pH3,while the addition of low con-centration H2S also had inhibition effect,the reduced corrosion rate remained low even in stage3,after the removal of H2S from the system.This last observation was unexpected because thesolubil-Fig.10.SEM surface morphologies of carbon steel tested at pH3,at the end of:(a) stage1(CO2),(b)stage2(CO2/H2S),(c)stage3(CO2).ities of iron sulfide and iron carbonate increase with decreasing pH [21].In order to better investigate this phenomenon,an additional experiment was performed at pH3.Fig.12shows the test pro-cedure,which was similar to the previous experiment procedure shown in Fig.2,except here it skipped stage1and started from stage2.The resulting OCP and LPR measurements at pH3are pre-sented in Fig.13.It was observed that the variation in OCP with increasing time in stage2and stage3showed the same trend as that in stage2and stage3in the previous test(Fig.7).The varia-tion in corrosion rate,however,was found to be different from that in the previous test.The corrosion rate was found to increase in stage3,after the removal of H2S from the system.Fig.14shows the Nyquist plots measured at the end of each stage.The impedanceY.-S.Choi et al./Electrochimica Acta 56 (2011) 1752–17601757Fig.11.Carbon steel corrosion rates measured at the end of each stage in pHs 3and 4conditions.spectra measured at stage 2showed a depressed capacitive loop at high frequencies and an inductive loop at low frequencies.At stage 3,the impedance spectra showed two capacitive loops at both high and low frequencies,whereas the low frequency inductive loop had disappeared.The diameter of Nyquist plot decreased with the removal of H 2S,which implies the loss of inhibition on the steel surface due to dissolution of iron sulfide,similar to the case in pH 4.Fig.15compares the polarization curves obtained at end of stage 3from the two pH 3tests that was,respectively,with and without stage 1exposure.It can be seen that when the specimen had gone through stage 1exposure,there was more reduction in theanodicFig.12.Experimental procedure for electrochemical corrosion study in pH 3with-out stage1.Fig.13.OCP and corrosion rate of carbon steel tested in pH 3.This test procedure skipped stage1.Fig.14.Nyquist plots of carbon steel tested at pH 3at the end of each stage (skip stage 1).reaction in stage 3.This implies that pre-corrosion of carbon steel in the stage 1promotes the formation of more stable iron sulfide in stage 2,and even provides more protection in stage 3possibly by the additional formation of iron carbonate as well.However,the detailed mechanism for the effect of pre-corrosion in CO 2envi-ronment (stage 1)is not understood,and further investigations are needed.As shown in Figs.3and 7,the addition of 100ppm H 2S to CO 2environment at pHs 3and 4caused a very fast response in the OCP and a sharp reduction of carbon steel corrosion rate.All the above mentioned observations and the associated discussions indicated that the addition of low H 2S concentration induced the formation of protective iron sulfide film on the steel surface.In addition,the films that caused these large changes in the electrochemical kinet-ics were thin and not observable in either SEM nor EDS [20].Fig.15.Polarization curves of carbon steel in pH 3at stage 3with and without stage 1.1758Y.-S.Choi et al./Electrochimica Acta56 (2011) 1752–1760 Although there have been a number of researchers investigatedthe mechanisms of iron sulfide formation,the actual mechanismof iron sulfide formation in H2S environment is nevertheless stillunclear,and it is still unclear whether the iron sulfide is formed bydirect solid state reaction or precipitation or both.In the presentstudy,the thermodynamics of iron sulfide formation were evalu-ated in order to understand the mechanism and kinetics of ironsulfide formation in the acidic solutions.When H2S dissolves into a water solution,the vapor–liquid equi-librium of H2S is described as:H2S(g)K H2S←→H2S(aq)(3) Upon dissolution,the dissolved H2S(aq)is involved in a sequence of chemical reactions as follows:H2S(g)K1←→H++HS−(dissociation of H2S)(4)HS−(aq)K2←→H++S2−(dissociation of HS−)(5)The concentrations of these sulfide species have been studied by a number of researchers using either experiments or theoretical thermodynamic models[22].If reaction(4)or(5)continues together with an increasing in concentration of Fe2+,a condition of supersaturation of mackinaw-ite at the steel surface may be achieved,which led to the nucleation and growth of mackinawite on the steel surface may occur via a pre-cipitation mechanism.In the present study,in order to calculate the degree of saturation of mackinawite,“[HS−]based expres-sions”were used instead of“[S2−]based expressions”because of the prediction of S2−concentration tends to be inaccurate[23].The equation used to calculate the degree of saturation of mackinawite (SS)is shown in the following:SS=[Fe2+][HS−]/[H+]K sp,mack(6)where[Fe2+],[HS−]and[H+]are the concentrations(mol/L)of fer-rous ion,bisulfide ion,and hydrogen ion,respectively.K sp,mack is the equilibrium solubility product of mackinawite.Thefilm precipitation will occur when the SS value exceeds unity,i.e.when the solution is saturated.The saturation degree of mackinawite depends on the solubility limit of mackinawite in the water solution.The solubility product of mackinawite(K sp,mack)at different temperatures had been expressed as follows[23]:K sp,mack=10(2848.779/T k)−6.347+log(K1)(7) where T k is the absolute temperature(in Kelvin)and K1is thefirst dissociation constant of H2S(in mol/L)of reaction(4).The degree of saturation for mackinawite at25◦C had been cal-culated at different pH values,and the results are plotted against Fe2+concentration as shown in Fig.16.In addition,the concentra-tions of Fe2+in the solution measured at the end of each stage for the tests at bulk pH of3and4,respectively,were also shown in Fig.17.As can be seen in Fig.17,all these Fe2+concentration values remained within the range of6–11ppm.From Fig.16,it can be seen that,with the Fe2+concentrations shown in Fig.17,at the tests at pHs3and4would have solution that was under-saturated with respect to mackinawite,and could not achieve saturation until pH becomes higher than6.This suggests that it is impossible to form mackinawite by precipitation out of bulk solution at pHs3and4 conditions.However,recent research in our lab on CO2corrosion has shown that,the pH measured near the surface of corroding carbon steel is higher than the bulk solution pH,in-spite of the fact that CO2has a good buffering capacity[24].Fig.18presents a comparison of pH values at25◦C in CO2environments,between the bulk solution versus that in near surface region over corroding steel[24].For the current pHs3and4corrosion tests in thiswork,Fig.16.Calculated degree of saturation for mackinawite at25◦C and100ppm H2S, plotted for different pH values as a function of Fe2+concentration.Fig.17.Ferrous ion concentrations at the end of each stage measured for tests at pHs3and4,respectively.Fig.18.pH values measured in solution bulk and near surface region of corroding steel(data from Ref.[22]).Y.-S.Choi et al./Electrochimica Acta 56 (2011) 1752–17601759Table 2Solubility limits of iron sulfides and iron carbonate (siderite)at room temperature.Phaselog(K sp )(mol L −1)at 25◦C Amorphous FeS −2.95Mackinawite −3.6Pyrrhotite −5.19Troilite −5.31Siderite−10.89similar surface pH values (≈6)were measured and was found to be higher than the bulk solution pH value.This finding indicates that more alkaline local water chemistry can be present in near surface region during CO 2corrosion.Thus,immediately over a steel surface undergoing corrosion,it is possible to generate a local alkaline con-dition that favors the precipitation of iron sulfide or iron carbonate on the steel surface.In order to verify the possibility of precipita-tion,the degree of saturation of various iron sulfides as well as iron carbonate at 25◦C,pH 6was calculated,and the results are plotted in Fig.19as a function of Fe 2+concentration.The solubility limits of iron sulfides and iron carbonate at 25◦C used in the calculation are shown in Table 2[25,26].As shown in Fig.19,the 25◦C,pH 6solution would be saturated for most of iron sulfides and for iron carbonate.This finding suggests that inan acidic solution,it is possi-ble to have a surface pH that causes local saturation and thus enable the formation of iron sulfides and iron carbonate film on steel sur-Fig.19.Calculated degree of saturation for iron sulfides and iron carbonate at 25◦C,100ppm H 2S and pH 6,plotted as a function of Fe 2+concentration.Fig.20.XPS spectra of carbon steel from pH 3solution at the end of stage 3:(a)S 2p,(b)C 1s,(c)O 1s,(d)Fe 2p.1760Y.-S.Choi et al./Electrochimica Acta56 (2011) 1752–1760face via precipitation.It is further noted that the above discussion indicates that it is also possible for the iron sulfide to form in an acidic solution via the solid state reaction mechanism,because the same favorable alkaline pH in near surface region may also serve to stabilize any surface iron sulfide that might have formed via the solid state mechanisms.Although the above theoretical calculation demonstrated the possibility of forming iron sulfide in the acidic solutions,in the present study,no sulfur was detected in the EDS analysis.It seems likely that the iron sulfidefilms formed in stage2when H2S was added were too thin to be detected in SEM and EDS analyses. In order to confirm the presence of iron sulfide on steel surface, XPS analysis was performed on samples that had been exposed to different stages and pHs.As an example,Fig.20shows the results of XPS analyses of carbon steel surface from pH3solu-tion at the end of stage3.Similar XPS spectra had been obtained from other samples at the end of stages2and3in both pHs used. As expected,S2p3/2peak was found(Fig.20(a))and its binding energy is consistent with that of iron sulfide[27].In addition,C1s (≈289eV)and O1s(≈532eV)peaks were also detected(Fig.20(b) and(c))which were consistent with the presence of iron carbon-ate[28,29].The presence of iron sulfide and iron carbonate were further evidenced in the detection of Fe2p3/2peak(Fig.20(d)) at binding energies of≈707eV and711eV,respectively[27,28]. 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