Sulfide Corrosion Research Articles

Study on Sulfide Distribution in the Operating Oil of Power Transformers and Its Effect on the Oil Quality

Corrosive sulfides in transformer oil could react with copper wire to produce cuprous sulfide, causing insulation failure. At present, both the quantitative measurement method and distribution of sulfur components in operating oil are not clear yet. In this paper, the existing types and contents of sulfides in oil samples with different alkyl groups and different voltage levels were investigated. With quantitative testing methods, the distribution of sulfur composition in the operating oil was analyzed. Results showed that the thiophene sulfide in transformer oil existed mainly in the form of benzothiophene with an unsaturation of 6 and dibenzothiophene with an unsaturation of 9. The content of monosulfide sulfide with unsaturation of 3 or 6 was the highest. The disulfide existed basically in the form of Dibenzyl disulfide (DBDS). The influence of sulfides on the oil quality were analyzed on this basis. Results showed that the existence of sulfides would increase the moisture content in oil. The absorbed moisture could cause the decrease of the breakdown voltage and rise of the dielectric loss. The above study could provide some engineering practice for understanding the sulphide distribution in transformer oils and further prevent the sulfur corrosion faults.

Characterization of Sludge Deposits from Refineries and Gas Plants: Prerequisite Results Requirements to Facilitate Chemical Cleaning of the Particular Equipment

In this paper, the method developed by the authors to separate the inorganic materials from the hydrocarbon of the sludge deposits, which is fast and can accurately identify very small quantities of inorganic materials, has been extended to characterize the 12 types of sludge samples collected from (a) a regeneration overhead acid gas condenser, (b) water draw-off pump’s suction strainer in a gas plant, and (c) condenser, inside vessels of inlet head, and head coiler tube equipment at gas plants. The results revealed that the major phases are (a) iron sulfide corrosion products with the hydrocarbon type of mixture of diesel and lube oil for a condenser and (b) carbonate scale in the form of calcium carbonate with the hydrocarbon type of lubricant oil for sludge deposits from a suction strainer for pumps, and drilling mud in the form of barium sulfate with no organic hydrocarbon or polymer for sludge samples from a water recycling pump. Moreover, the major phases for inorganic materials built up in a condenser, inside the vessel’s inlet head, and the head coiler tube revealed that iron oxide corrosion products are found in the steam drum, and iron sulfate corrosion products are built up in the condenser. The presence of dissolved oxygen in the boiler feed water is indicated by a high wt% of iron oxide corrosion product in the form of magnetite (Fe3O4), which appeared in the inorganic materials built up in the condenser steam drum. Knowing accurately which phases and their wt% were involved in the inorganic materials can guide the field engineers to facilitate efficient cleaning of the equipment by drawing up the right procedures and taking preventive action to stop the generation of those particular sludge deposits.

Universalism of Hydrogen Sulfide and Carbon Dioxide Corrosion Inhibitors in Conditions of Oil Production and Processing

Qualitative criteria for the universalism of hydrogen sulfide and carbon dioxide corrosion inhibitors and their quantitative indices for the corrosion of carbon steel are proposed. They include the maximum value of the total corrosion rate in the presence of H2S and CO2 and with simultaneous limitation of the concentration of the inhibitors themselves. The criteria define a minimum reduction in hydrogenation of steel, suppression of hydrogen diffusion into the metal, contain requirements for the bactericidal ability of inhibitors by limiting the number of cells of sulfate-reducing bacteria and producing hydrogen sulfide, and the requirements for their biodegradability. It is shown that a number of domestic inhibitors of hydrogen sulfide and carbon dioxide corrosion of the new generation of the INKORGAZ series fully satisfy the proposed criteria for universalism.

High-temperature corrosion of a UNS K03006 steel pipe in a crude oil vacuum residue distillation unit

Abstract A carbon steel pipe of ASTM A106 grade B [UNS K03006] specification was in service of vacuum residue in a crude oil vacuum unit at temperatures ranging from 293 to 350 °C. After 20 years of service it failed due to a combination of sulfidic and naphthenic acid corrosion. This failure motivated this is work, where the mechanism of corrosion failure mechanism is studied, based on the microstructural characterization of the corroded surfaces of coupons tested in a laboratory simulated vacuum residue environment, with variations in temperature and exposure times. Experimental results showed that at 310 °C, the preferential formation of a homogeneous passive iron sulfide film occurred, which promoted general sulfide corrosion. However, the greatest corrosion rates occurred at 350 °C, due to the generation of sour primary distillates and the fragmentation of the vacuum residue molecule, which triggered a naphthenic acid corrosion mechanism, which caused localized attack corrosion. It is concluded that the most important factor to be monitored in vacuum residue service in crude oil vacuum residue distillation units, in order to predict and prevent corrosion, is the temperature. Specifically, operation temperatures above 310 °C should be avoided, because high corrosion rates and the combination with localized attack in the forms of pitting and grain boundary dissolution. In order to prevent failures in vacuum residue pipes, closed interval thickness surveys and close temperature monitoring are recommended.

Hydrogen and corrosion resistance of Ni-Co superalloys for gas turbine engines blades

Purpose: This paper is devoted to the investigation of gaseous hydrogen and ash gas turbine fuel influence on the mass loss in long-term corrosion and mechanical properties of cast heat-resistant blade materials. It has been established that the level of corrosion resistance of the investigated alloys (Ni59Cr21Co10W4Ti3Al3MoLa (SM-104-VI); Ni57Cr16Co12W6Ti4Al3Mo2Hf (SM-90-VI); Ni57Cr16Co11W6Ti4Al4Mo2Hf (SM-88U-VI)) correlated with the chromium content and is the highest among similar materials. The advantage of SM-104-VI alloy increases with the increasing of time base and temperature. Design/methodology/approach: This work presents research results concerning corrosion and hydrogen resistance of a investigated alloys examined at a standart mechanical tests under short-term static tension was determined on smooth cylindrical five-time samples with a diameter of the working part 5 mm at speed 1 mm/min. The destructed areas were examined by optical and electron microscopes with computer image analysis. Findings: It has been found that the level of resistance of the investigated alloys high- temperature sulfide and oxide corrosion in the ash of the gas turbine fuel is correlated with the criterion alloying and is the highest among the known materials of the blades. The value of specific mass loss decreases in the order of SM-88U-VI, SM-90-VI, SM-104-VI. Moreover, its advantage over alloys of SM-90-VI and SM-88U-VI as bigger as the time the corrosive environment. Research limitations/implications: An essential problem is the verification of the results obtained using the standart mechanical tests, computer-based image analysis and other methods. Practical implications: The observed phenomena can be regarded as the basic explanation of reduces the plasticity characteristics of the alloys for gas turbine blades. Originality/value: The value of this work is that increasing temperature reduces the negative influence of hydrogen, however, even at 900°C, the values of elongation and transverse contraction in hydrogen is lower than in the air. For a short stretch in the temperature interval 20-900°C the least sensitive to the action of hydrogen at a pressure of 30 MPa is a single crystal SM-90-VI alloy.

Galvanic Corrosion of Mild Steel Under Iron Sulfide Layers

Iron sulfide corrosion product layers have recently become the center of attention in H2S corrosion. The iron sulfides role on mild steel corrosion exposed to H2S containing environments has been reported to be related to their semi-conductive properties. The two most stable phases, pyrite and pyrrhotite have similar resistivity and a more positive open circuit potential (OCP) when compared to mild steel OCP. In an earlier study, the authors reported a comparable electroactivity to what was measured on an X65 mild steel surface. Given conditions for establishing a galvanic cell are present in a conductive electrolyte, a corrosion product layer containing sulfide phases could enhance the rate of cathodic reactions by providing a larger cathodic surface area. Also, the mixed potential established between these layers with the mild steel is often more positive than the OCP for the uncoupled steel. This results in an intensified iron dissolution rate. In conditions where the steel is locally exposed to the corrosive media, this leads to localized corrosion. The evidence for a galvanic effect related to iron sulfides coupling to mild steel has been mostly circumstantial. The galvanic corrosion that was attributed to such conditions was a conclusion that was reached through deductive reasoning, without direct proof. In the current study, zero resistance ammeter (ZRA) measurements were utilized to measure the magnitude of the galvanic current between coupled X65-pyrite and X65-pyrrhotite electrodes. Pyrite and pyrrhotite electrodes were prepared using geological specimens. The experiments were conducted in a deaerated conductive aqueous solutions at different pH at room temperature with iron sulfide surface area being seven times higher than the X65 steel surface area. The experimental results for the same cathode to anode ratio showed that a higher galvanic current was measured at the X65-pyrrhotite couple versus X65-pyrite surfaces. It is noteworthy that upon exposure to an aqueous solutions containing H+, pyrrhotite undergoes a surface reduction to troilite and produces H2S. In a more acidic environments the produced H2S does not have a substantial effect on the corrosion currents. However, in aqueous solutions with limited available H+, the produced H2S plays a significant role in enhancing the corrosion currents. It was shown in a prior publication that at pH 5.0 the currents at the pyrrhotite surface was higher than what was measured at the pyrite or X65 surfaces. This resulted in a much higher galvanic current at the X65-pyrrhotite surface. Figure 1

Hydrogen Sulfide Corrosion of Carbon and Stainless Steel Alloys in Mixtures of Renewable Fuel Sources under Co-Processing Conditions

Corrosion rates of steel alloys were investigated in gas oil and its mixture with waste cooking oil and animal waste lard over 1, 3, 7 and 21 days under desulfurizing condition. Co-processing conditions were attempted to simulate by batch-reactor experiment at temperatures between 200 and 300oC and pressures between 20 and 90 bar in the presence of 2 volume% hydrogen sulfide. Integral and differential corrosion rates were defined by weight losses. Intense sulfide corrosion of carbon steels was less impacted by the biomass sources. Thinner scales in gas oil was probably due to frequent cohesive failure, whereas thicker layers in biomass mixtures were allowed to form to afford limited physical protection. The high corrosion rate of low alloy steel with temperature over time is related to inefficient protection by the metal sulfide scales. Greater activation energy and enthalpy balance in the formation of activated complex is expected to reflect in thick cohesive scales. Loose layers and the less unfavorable entropy balance in the transition state did not lead to valuable barrier protection. High sulfide corrosion resistance of stainless steels is in chemical in nature markedly impacted by the biomass fuel sources and contributed especially by the acidic species. Corrosion rates increased with temperature by magnitude similar to those of carbon steels, which probably owes to the less unfavorable entropy and free energy balance between the initial and transition states of the reactants.

A Study of the Pitting and Uniform Corrosion Characteristics of X65 Carbon Steel in Different H2S-CO2-Containing Environments

There have been increasing concerns related to the challenges posed by hydrogen sulfide (H2S) corrosion to the integrity of oilfield pipeline steels. In environments containing variable quantities of both carbon dioxide (CO2) and H2S gas, the corrosion behavior of carbon steel can be particularly complex. There is still no universal understanding of the changes in the mechanisms, sequence of electrochemical reactions and impact on the integrity of carbon steel materials as a result of changes in H2S-CO2 gas ratio. The film formation process, film characteristics, and morphology in CO2- and H2S-containing systems are also known to be different depending upon the environmental and physical conditions and this influences the rates of both general and pitting corrosion. Questions still remain as to how the combined presence of CO2 and H2S gases at different partial pressure ratios influence the corrosion mechanisms, as well as initiation and propagation of surface pits. This paper presents an investigation into the overall (i.e., general and pitting) corrosion behavior of carbon steel in CO2-H2S-containing environments. The work explores the impact of changes in ratios of CO2 and H2S partial pressures at both 30°C and 80°C in a 3.5 wt% NaCl solution. All experiments are performed at atmospheric pressure, while H2S gas content is varied at 0 ppm (0 mol%), 100 ppm (0.01 mol%), 1,000 ppm (0.1 mol%), 10,000 ppm (1 mol%), and 100,000 ppm (10 mol%) in H2S-CO2 corrosion environments. Corrosion film properties and morphology are studied through a combination of scanning electron microscopy and x-ray diffraction. The results show that the morphology and composition of iron sulfide formed changes with H2S gas concentration because of the continuous interaction of the corrosion interface with the corrosion media even in the presence of initially formed FeS (mainly mackinawite). This often leads to the formation of a different morphology of mackinawite as well as different polymorphs of FeS. This also has the impact of either increasing or decreasing the uniform corrosion rate at low and higher concentration of H2S gas depending on the temperature. Pitting corrosion is also evaluated after 168 h to determine the impact of increasing H2S content on the extent and morphology of pitting corrosion attack. The results from the pitting corrosion investigation show that increased and severe pitting corrosion attack occurs at higher H2S concentration and temperature. The morphology of pitting corrosion attack is also linked to the changes in the H2S content with an indication of a critical concentration range at which the nature of attack changes from narrow and small diameter pits to severe localized attack. The critical concentration threshold for such transition is shown in this study to reduce with increasing temperature.

Sulfur and Total Carboxylic Acid Number Determination in Vacuum Gas Oil by Attenuated Total Reflectance Fourier Transform Infrared Spectroscopy

Sulfur removal is one of the key functions of vacuum gas oil (VGO) hydrotreating reactors. Knowing feed and product properties real-time or near-real-time improves reactor operations. The VGO section of crude distillation unit is also prone to severe high-temperature sulfidic and naphthenic acid corrosion. In this article, we evaluate a single-reflectance attenuated total reflectance Fourier transform infrared (ATR-FTIR) spectroscopy as a possible quick and cost-effective methodology to determine total carboxylic acid number (TCAN) and total sulfur content of VGO. The study shows that single-reflectance diamond ATR crystal methodology has the right signal-to-noise ratio to accurately predict TCAN and total sulfur within the primary method’s repeatability. Statistical models have been developed using 64 sample sets of vacuum gas oil and out of which 10 samples were used for the cross-validation of the model. The range of TCAN in VGO samples used in this study was between 0.37 and 13.8 mg KOH/g, and sulfur ...

Design of anti-tarnish sterling silver Ag-Cu-Zn alloy and investigation of silicon addition influence on mechanical and corrosion characteristics

This paper presents investigations of the influence of silicon addition on the mechanical and corrosion characteristics of the sterling silver Ag-Cu-Zn alloys. The procedure for obtaining Ag-Cu-Zn-Si alloys in small ranges of composition was also presented. Vickers hardness tests and three electrochemical tests were performed on the samples in this study. Open circuit potential measurements, linear polarization resistance method, and potentiodynamic polarization tests were employed to determine corrosion characteristics of the alloys. The materials were tested in 0.9% NaCl solution, artificial sweat, 0.1 and 0.01 M sodium sulfide solutions. It was shown that addition of silicone increases hardness and generally improves sulfidation resistance and corrosion characteristics in near-neutral chloride solutions of the Ag-Cu-Zn alloys.

Corrosion cracking of carbon steels of different structure in the hydrogen sulfide environment under static load

Hydrogen sulfide corrosion is one of the main reasons of steels destruction in the oil and gas industry. Damages appear as a result of corrosion and hydrogen embrittlement, and corrosion cracking occurs when the load is applied. The influence of the steels structure on its stress corrosion cracking under the loads in hydrogen sulfide environment is insufficiently studied. The aim of the study is to determine the influence of the steels structure on its corrosion, hydrogenation and corrosion cracking in the NACE hydrogen sulfide solution.It was established that the corrosion rate and hydrogenation of steel У8 in the NACE solution grows when the structure dispersion increases from perlite to sorbite, troostite and martensite. The corrosion rate and hydrogenation of steel 45 are the greatest in pearlite-ferrite, while the smallest - in sorbite.The corrosion of steels У8 and 45 in the NACE solution is localized: the average size of the ulcers is 50 ... 80 μm on the steel У8 and 45 ... 65 μm on steel 45. The depth of ulcers is maximal on the steel У8 with the martensite structure (~ 260 μm) and on the steel 45 with the troostite structure (~ 210 μm).Static load (σ = 300 MPa) increases the hydrogenation of steels in the hydrogen sulfide environment. The concentration of hydrogen in steel У8 with troostite structure increases by ~ 1.8 times. The concentration of hydrogen in steel 45 with troostite and martensite structures increases by ~ 1.2...1.3 and by ~ 1.4...1.6 times, respectively.The steel У8 with martensite and perlite structures and steel 45 with troostite structure has the lowest resistance to corrosion cracking. Steels destruction depends on both hydrogen permeation and the corrosion localization, which leads to the increase of the microelectrochemical heterogeneity of the surfaces.

Research on hydrogen-induced cracking behavior of normalized pipeline steel

Hydrogen sulfide corrosion test was used to test the hydrogen-induced cracking sensitivity of the normalized BNS pipeline steel. The microstructure and morphology of hydrogen induced crack(HIC) of the normalized BNS pipeline steel after hydrogen sulfide corrosion test were observed with optical microscopy(OM), scanning electron microscopy(SEM). Combined with electron probe microanalyzer(EPMA) and hardness test, the hydrogen-induced cracking behavior of BNS pipeline steel was studied from the aspects of microstructure, crack morphology, center segregation and harness. The results showed that the pearlite band with high hardness caused by center segregation of C and Mn was the main crack initiation and propagation path for the long-size and linear shape hydrogen induced crack at the center of plate thickness, and the type of crack propagation was transgranular. Some tiny hydrogen induced crack nucleated from the small calcium-aluminate inclusion and the tiny hydrogen induced crack would not propagate to form long-size cracks with no suitable propagation path existing around the inclusion.

Evaluation of corrosion products formed by sulfidation as inhibitors of the naphthenic corrosion of AISI-316 steel

Naphthenic acids present in oil from most regions worldwide currently stand as the main responsible for the naphthenic corrosion problems, affecting the oil-refining industry. The phenomenon of sulfidation, accompanying corrosion processes brought about by naphthenic acids in high-temperature refining plant applications, takes place when the combination of sulfidic acid (H2S) with Fe forms layers of iron sulphide (FeS) on the material surface, layers with the potential to protect the material from attack by other corrosive species like naphthenic acids. This work assessed corrosion products formed by sulfidation as inhibitors of naphthenic corrosion rate in AISI-316 steel exposed to processing conditions of simulated crude oil in a dynamic autoclave. Calculation of the sulfidation and naphthenic corrosion rates were determined by gravimetry. The surfaces of the AISI-316 gravimetric coupons exposed to acid systems; were characterized morphologically by X-Ray Diffraction (XRD) and X-ray Fluorescence by Energy Dispersive Spectroscopy (EDS) combined with Scanning Electron Microscopy (SEM). One of the results obtained was the determination of an inhibiting effect of corrosion products at 250 and 300°C, where lower corrosion rate levels were detected. For the temperature of 350°C, naphthenic corrosion rates increased due to deposition of naphthenic acids on the areas where corrosion products formed by sulfidation have lower homogeneity and stability on the surface, thus accelerating the destruction of AISI-316 steel. The above provides an initial contribution to oil industry in search of new alternatives to corrosion control by the attack of naphthenic acids, from the formation of FeS layers on exposed materials in the processing of heavy crude oils with high sulphur content.

Formation of passivating layers by 1,2,4-triazole derivatives on copper in aqueous solutions

Ellipsometry and electrochemical measurements are used to study the adsorption of some substituted 1,2,4-triazoles on copper and their effect on dissolution of copper in aqueous buffer solutions at pH 7.4. It is found that the adsorption of triazole compounds on copper is polymolecular at potential Е = 0.0 V, in relation to a normal hydrogen electrode. The first layer is described by the Temkin equation with free adsorption energy (−ΔGa0) = 55.2–76.3 kJ/mol and an energy heterogeneity factor that varies from 0.91 to 2.5. The maximum value of −ΔGa0 is found for an acid and a hydrogen sulfide corrosion inhibitor that is a mixture of triazole derivatives. The same inhibitor is the one least sensitive to the energy heterogeneity of the surface of a copper electrode, due to its high chemical reactivity and ability to be adsorbed on different active sites. This inhibitor is likely chemisorbed on copper and forms an ultrathin coating in an aqueous solution that is vastly superior to similar coatings produced by the familiar corrosion inhibitors of triazole group compounds in protecting against atmospheric corrosion.

Assimilation of Pipe Steel Extra-Furnace Treatment and Casting Technology with Specification for Resistance to H2S Media Under Casting and Rolling Complex Conditions

Comprehensive analysis is provided for the effect of production parameters on the manufacture of steel produced under conditions of a casting and rolling complex (CRC) on rolled production hydrogen-induced cracking (HIC) resistance and sulfide corrosion cracking (SCC) in H2S-media. For the first time, in metallurgical practice under casting and rolling complex conditions a general concept of technology is developed for extra-furnace treatment and casting of steel with specifications for HIC and SSC with simultaneous provision of rolled product cold resistance (KCV at –50°C, KCU at –60°C), and based upon it assimilation of rolled product and oil and gas pipe mass production.

How effective are reducing plasma afterglows at atmospheric pressure in removing sulphide layers: Application on tarnished silver, sterling silver and copper

A plasma afterglow from a gas mixture of 5 vol% H2 in He is able to remove tarnish layers on pure silver in a matter of seconds. This dry, localized, and noncontact cleaning technique is a promising method to clean historical objects where silver is combined with organic materials and where traditional cleaning techniques are not recommended. However, historical objects are often manufactured with silver alloys but somehow their tarnish layers are removed less effectively with plasma treatments. To understand the different impact of the afterglow, the surfaces of corroded silver, sterling silver, and copper coupons are characterized before and after plasma treatment by a multianalytical approach combing optical and confocal microscopy, scanning electron microscopy coupled to energy dispersive X‐ray analysis and chronopotentiometry. The analyses demonstrate that the few hundred nanometre‐thick tarnish layer on pure silver is transformed through the whole thickness resulting in a porous metallic film. On top of that metallic film, some isolated remnant Ag2S particles are found. For sterling silver, a yellowing of the surface occurs. The Ag‐rich corrosion products are reduced to a large extent, while the Cu‐rich corrosion products are only partially reduced. For corroded copper, no apparent visual change is observed at a macroscopic scale, although the morphology of the surface changed. The results allow an evaluation of the cleaning efficiency and provide a deeper understanding of hydrogen plasma effects on the transformation of sulphide corrosion layers at atmospheric pressure.

Sulfide Scaling and Corrosion of Carbon Steel in a Sour Medium

The damage caused by the building up of scale inside wellbores and pipelines costs millions of pounds each year. A better understanding of scale formation and the kinetic nature of the process is essential, for asset management in general and the development of new protection approaches. Surface scale formation is one of the important factors related to the corrosion rate. The internal corrosion of carbon steel in the presence of hydrogen sulfide represents a significant problem for both oil refineries and gas treatment facilities/pipelines. Many studies have revealed that the system is complex since more than one iron sulfide compound may form. However, the kinetics of scale formation, such as the nucleation and growth processes of the scale are not at all well-understood and how corrosion inhibitors interact with scales. The kinetics of the scale formation will be investigated by using a variety of methods, some more successful than others. The methods employed include SEM, TEM, EDX, and Raman analysis, and this was done with the aim of obtaining the physical structure, the chemical composition and the crystal structure of the iron sulfide scale formed at different time scales.

Effects of ultrasonic peening treatment on hydrogen sulphide corrosion behaviour

ABSTRACTAfter being subjected to ultrasonic peening treatment (UPT), the resistance of X65 pipeline steel to hydrogen sulphide corrosion was investigated through electrochemical, immersion and slow-strain-rate testing. In addition, the UPT-induced compressive residual stresses layer and related changes in the steel near-surface microstructure and hardness were examined by scanning electron microscopy, optical microscopy and X-ray diffraction. The obtained results revealed that UPT was able to significantly improve the corrosion potential of X65 pipeline steel and reduce its hydrogen sulphide corrosion rate, while the formation of the compressive stress layer increased the steel’s tensile strength and inhibited hydrogen blistering.

INFLUENCE MOLYBDENUM ON THE CORROSION-MECHANICAL PROPERTIES OF CARBON STEEL WELDED JOINTS

The paper studies the impact of molybdenum on the corrosion and mechanical properties of welded joints of steel boiler. Found that the most high and stable toughness values and resistance to cracks and sulfide stress corrosion cracking of the weld metal pipe steels are achieved when the concentration of molybdenum in it from 0.2 to 0.3%, which implemented in electrode input molybdenum powder coating in an amount of 0.5-1.0%. The optimum chemical composition of weld metal provides getting fine-grained structure, holding a small amount of non-metallic inclusions of globular form.

Decline in Sulfate Reducing Bacterial Consortia by the Sulfur Oxidizing Bacterial Activity

In anaerobic environment, dominant sulfate reducing bacteria (SRB) consortia are found to cause many serious problems to the oil such as sour oil, hydrogen sulfide (H2S), and metal corrosion. They are obligatory anaerobes using sulfate, thiosulfate and sulfites as final electron acceptors and use organic acids or alcohols as a carbon source. In the aerobic system, other dominant niches are sulfur-oxidizing bacteria (SOB) playing role in biological oxidation of hydrogen sulfide. These SOB convert H2S into elemental sulfur (S0) by partial oxidation. Since the levels of reduction and oxidation are dependent on the oxygen concentration. In the condition of limited oxygen, sulfate generated by SOB can also be contributed to the reduction of oxygen which encourages SRB proliferation in anaerobic environment. In this research, we were interested to manage the conditions to control the dominant niches by management of oxygen levels. In the experiment, the concentration of sulfate concentration, acidity, sulfide were determined to understand the microbial activity. The results showed after cocultures of SRB and SOB niches in the present of oxygen, the activity of SRB was prevented since a decrease in H2S product but an increase in sulfate concentration were observed. This revealed a promising niches of SOB isolates in the presence of oxygen and active in high sulfide removal. These data indicated the situation suitable for either SOB or SRB community is dependent on oxygen concentration. The management of SOB community can be used as an alternative method to remove contaminating H2S from the system.