Showing papers on "Sour gas published in 1998"

Solubility of Carbon Dioxide in Aqueous Solutions of 2-Amino-2-methyl-1,3-propanediol

Abstract: The equilibrium solubility of carbon dioxide in aqueous solutions of 2-amino-2-methyl-1,3-propanediol (AMPD) has been measured at (30, 40, and 60) °C and the partial pressure of carbon dioxide ranging from (0.5 to 3065) kPa. The concentrations of the aqueous solutions were (10 and 30) mass % AMPD. The tendency of the solubility of carbon dioxide in 30 mass % AMPD aqueous solution at 40 °C was found to be similar to that in 30 mass % N-methyldiethanolamine aqueous solution.

Acid gas fractionation

Abstract: A process to bulk separate H 2 S and CO 2 from a sour gas by first cooling the inlet sour gas, passing the cooled sour gas through a separator and removing a liquid acid gas as a bottoms product in a fractionation tower, and then either pumping or free flowing the liquid acid gas into a disposal well. Potential sulphur deposition problems are controlled by recycling liquid acid gas to the plant inlet.

Technological aspects of the microbial treatment of sulfide-rich wastewaters: A case study

Abstract: Thiobacillus denitrificans has been shown to be an effective biocatalyst for the treatment of a variety of sulfide-laden waste streams including sour water, sour gases, and refinery spent-sulfidic caustics. The term 'sour' originated in the petroleum industry to describe a waste contaminated with hydrogen sulfide or salts of sulfide and bisulfide. The microbial treatment of sour waste streams resulting from the production or refining of natural gas and crude oil have been investigated in this laboratory for many years. The application of this technology to the treatment of sour wastes on a commercially useful scale has presented several technical barriers including substrate inhibition (sulfide), product inhibition (sulfate), the need for septic operation, biomass recycle and recovery, mixed waste issues, and the need for large-scale cultivation of the organism for process startup. The removal of these barriers through process improvements are discussed in terms of a case study of the full-scale treatment of sulfide-rich wastewater. The ability of T. denitrificans to deodorize and detoxify an oil-field produced water containing sulfides was evaluated under full-scale field conditions at Amoco Production Co. Salt Creek Field in Midwest, WY. More than 800 m3/d of produced water containing 100 mg/L sulfide and total dissolved solids of 4800 mg/L were successfully biotreated in an earthen pit (3000 m3) over a six-month period. Complete removal of sulfides and elimination of associated odors were observed. The system could be upset by severe hydraulic disturbances; however, the system recovered rapidly when normal influent flow rates were restored.

FTIR measurements of acid‐gas–methyldiethanolamine systems

Abstract: The standard industrial process for the purification of natural gas is to remove acid gases, mainly hydrogen sulfide and carbon dioxide, by the absorption and reaction of these gases with alkanolamines, but the lack of reliable and accurate vapor–liquid equilibrium (VLB) data impedes the commercial application of more efficient alkanolamine systems A novel Fourier-transform infrared (FTIR) technique was developed to make in-situ VLE measurements of acid-gas-aqueous alkanolamine systems and to improve the accuracy of VLE measurements at low hydrogen sulfide and carbon dioxide concentrations VLE measurements of low carbon dioxide and hydrogen sulfide concentrations in aqueous mixtures of methyldiethanolamine (MDEA) are reported using the new FTIR technique

Sulfur Solubility in Sour Gas: Predictions with an Equation of State Model

Abstract: The Peng−Robinson equation has been used to describe the phase behavior of elemental sulfur and the solubility of sulfur in natural gas mixtures. The sulfur is modeled as S8 in all phases with b = 0.131 22 m3/kmol and a(T) = 6.1051 + 2568.1/T MPa (m3/kmol)2. Vapor pressures varying by 5 orders of magnitude are reproduced with a maximum error of 11% over a temperature range from 120 to 640 °C, and the calculated saturated liquid density is within 1% of the data up to 320 °C and within 3.6% at all temperatures. Calculated vapor densities are inaccurate because of the dissociation of S8 at low pressure or high temperature. The fugacity for pure solid sulfur is found from a separate model. A calculated phase diagram for sulfur−hydrogen sulfide matches three-phase lines and the solid−liquid−liquid−vapor quadruple point. Solubilities calculated from the proposed model show all the qualitative behaviors in the data and agree very well with experimental data at higher pressures in gases covering a broad range of ...

A new absorbent for carbon dioxide and hydrogen sulphide absorption process

Abstract: The results of investigations on the process of CO2 and H2S absorption in a new absorbent, propylene carbonate (PC) modified by triethanoloamine (TEA), are presented. The data on CO2 and H2S solubility, as well as the results of measurements of the absorption rate of these gases in the TEA–propylene carbonate solution are reported. The measurements were carried out in the range of parameters most interesting in terms of the commercial application of the process.The data on CO2 and H2S solubility in the TEA–propylene carbonate solution are presented in the form of correlation equations as functions of gas partial pressure, temperature and TEA concentration. CO2 and H2S diffusion coefficients obtained in kinetic investigations are correlated with temperature and TEA concentration. The mechanism of CO2 and H2S absorption in the TEA–propylene carbonate solutions is explained. Application of the propylene carbonate with TEA as an additive in the CO2 absorption process has been tested in a pilot plant and will be offered as a commercial process.

Experimental and Numerical Modeling of Sulfur Plugging in a Carbonate Oil Reservoir

Abstract: Many oil and gas reservoirs in the United Arab Emirates produce large amounts of sour gas, mainly in the form of hydrogen sulfide. In addition to creating problems in the production line, wellbore damage is often reported due to the precipitation of elemental sulfur in the vicinity of the wellbore. While there have been several studies performed on the role of solid deposition in a gas reservoir, the role of sulfur deposition in oil reservoirs has not been investigated. This article presents experimental results along with a comprehensive wellbore model that predicts sulfur precipitation as well as plugging. The experiments were conducted in a core (linear) system. Both analytical and numerical modelings were performed in a linear coordinate system. Data for the numerical model was obtained from both test tube and coreflood experiments. By using a phenomenological model, the wellbore plugging was modeled with an excellent match (with experimental results). The crude oil was de-asphalted prior to conductin...

Diisopropanolamine Biodegradation Potential at Sour Gas Plants

Abstract: The potential for aerobic and anaerobic biodegradation of a sour gas treatment chemical, diisopropanolamine (DIPA), was studied using contaminated aquifer materials from three sour gas treatment sites in western Canada. DIPA was found to be readily consumed under aerobic conditions at 8°C and 28°C in shake flask cultures incubated with aquifer material from each of the sites, and this removal was characterized by first-order kinetics. In addition, DIPA biodegradation was found to occur under nitrate-, Min(IV)., and Fe(III)-reducing conditions at 28°C, and in some cases at 8°C, in laboratory microcosms, DIPA loss corresponded to consumption of nitrate, and production of Mn(II) and Fe(II) in viable microcosms compared to corresponding sterile controls. A threshold DIPA concentration near 40 mg/L was observed in the anaerobic microcosms. This report provides the first evidence that DIPA is biodegraded under anaerobic conditions, and our data suggest that biodegradation may contribute to DIPA attenuation under aerobic and anaerobic conditions in aquifers contaminated with this sour gas treatment chemical.

Acid/Sour Gas Management in the Petroleum Industry

Abstract: Due to decreasing world demand for elemental sulphur, the economics of recovering sulphur from sour natural gas has become unfavorable. At the same time, air emission standards and regulations are becoming ina'eaSingiy stringent, increasing the economical strain on oil and gas companies producing sour natural gas. Hydrocarbon producing companies are in search of environmentally-friendly and cost-effective methods for dealing with acid gas, which is produced in association with sour natural gas. In recent years. compressed acid gas re-injection into a porous formation has emerged as a viable alternative to sulphur recovery with the added advantage of eliminating air emissions. As an alternative, some operators also solubilize the sour/acid gas into disposable formation water and dispose acid water into porous formation. In addition, to take advantage of high solubility of acid/sour gas into light hydrocarbon solvent, some operators are also injecting light hydrocarbon solvent containing acid/sour gas into the depleted oil leg as a miscible flood enhanced oil recovery (EOR) technique. Laboratory tests and results will be presented in this paper which illUSb'ate the pros and cons of all these alternative processes to manage the produced acid/sour gas in the petroleum industry. be "sweetened" to selectively remove the acid gas components before the gas can be transported and sold for commercial use. Among the sweetening processes, amine extraction process is the most commonly used process in die petrolewn industry. The sweetening process results in die production of acid gas-free "sales" gas, and a rich waste gas stream consisting of virtually pure carbon dioxide (COJ and hydrogen sulphide ~S). The waste gas stream is commonly referred to as acid gas. The economics of recovering sulphur from acid gas has become unfavorable because of decreasing world demand for elemental sulphur. Air emission standards and regulations are becoming increasingly stringent, increasing die need for an environmentally-friendly and cost-effective methods for dealing with the acid gas streams. There are various alternatives to deal with the acid gas mixtures. These alternatives are: . Injection of compressed acid gas into the porous formation. . Dispose acid gas with disposable fonnation water. . Solubilize acid gas into light hydrocarbon solvent and inject the solvent containing acid gas component into the depleted reservoir as a miscible flood enhanced oil recovery (EOR) technique. Acid gas compression and re-injection into depleted resuvoirs or disposal zones, similar to produced water disposal, is a viable alternative to traditional sulphur recovery processes with the added advantages of reducing greenhouse gas emissions and providing pressure support for producing reservoirs. 1-4 Acid gas recovered from die amine process contains water, and hence, proper strategic design is essential to address ilie issue of whether an acid gas stream needs dehydration or not The appearance of a free liquid water phase due to changes in temperature and pressure conditions can cause significant operating problems (i.e. compressor damage, corrosion, hydrates formation, etc.). Currently, most injection schemes include dehydration facilities to ensure ilie absence of free Introduction Sour natural gases are produced as either free gas or as liberated solution gas from sour oil. These gases must 2 ACID/SOUR GAS MANAGEMENT IN THE PETROlEUM INDUSTRY SPE 49522 in the injection gas is considerably greater than dlis value. In other instances, the H2S content in the acid gas streams are seen to be lower as well (in die range of 100/0 and the remaining component is COJ. Injection of Compressed Acid Gas into the Porous Formation. Sour natural gases are sweetened by removing H2S and CO2 by absorption with a regenerative solvent in an amine plant. The acid gas mixture of H2S, CO2, and a small amount of light hydrocarbons leaves the sweetening unit saturated with water at the amine still conditions of low pressure and high temperature. The gas mixture is then compressed in 3 to 4 stages. After each stage, the gas mixture is cooled, without entering the two-phase region. Condensed water is removed after each stage. After the last stage, the mixture travels down the pipeline into the disposal well. Ideally at the fmal compressor discharge pressure, the mixture will be supercritical. Further cooling in the pipeline will increase the density without a phase change, increasing the hydrostatic head of fluid in the well and reducing the required injection pressure. The operator must ensure d1at the mixture does not cool below its water saturation temperature, especially in the hydrate region, to avoid corrosion and hydrate plugging of the pipeline and wellbore. Corrosion and hydrates may occur when the gas is saturated with water. Due to the safety hazard associated with acid gas equipment failure, most injection schemes currently include dehydration facilities to ensure the acid gas is undersaturated throughout the system. Unfortunately, dehydration facilities and stainless steel comprise a major portion of the capital cost of re-injection facilities. Methanol injection is an option to combat corrosion and hydrate fonnation, but can significantly increase operating expenses. Although there is little experimental data on acid gas mixture, the solubility of water in pure H2S and CO2 lead to some interesting hypotheses. The ability of the pure c0mp01Dlds to hold water in the vapor phase decreases as the pressure increases up to about 3000 kPa (400 psi) for H2S and 6000 kPa (900 psi) for CO2. At higher pressures dte water holding capacity of the gases increases, corresponding to a higher water absorption capacity in dte liquid phase or dense phase compared to the vapor phase. In both cases, inaeasing the temperature allows more water to be absorbed in the gas phase. Small amounts of methane substantially reduce the water absorption ability of both components. It is assumed d1at solubility of water in the gas mixtures mimics the trend of dte individual components, then a minimum water holding capacity exists at some pressure. I In a re-injection facility, over each compression stage, dte pressure and temperature water in die system and reduce corrosion and hydrate concerns. Dehydration facilities comprise a major portion of die capital cost of re-injection facilities. Alternatively, stainless steel materials and med1anol injection are used to combat corrosion and hydrate formation conditions. However, diis alternative is also expensive and poses significant operating problems. An alternative and cost-effective approach would be to keep die water in die vapor phase throughout the injection circuit, eliminating die need to dehydrate. To design an optimized injection strategy widiout dehydrating the acid gas, detennination of thermodynamic properties (i.e. water content, dewpoint, bubble point, and hydrate points) of die acid gas is necessary. The system may also be designed to inject die mixture as a dense phase, above die critical point, reducing die required injection pressure and horsepower requirement due to die hydrostatic head of die colwnn of fluid in die injection wellbore. The hydrate curve information will ensure diat the system never enters die hydrate region, reducing die risk of pipeline plugging. An alternative approach is to solubilize die acid gas in produced or source water in a high pressure contacting tower on the surface, followed by subsequent injection of die sour water.s An understanding of die solubility of die injected gas or insitu water phase is essential in order to quantify die speed of migration of die injected gas (in a direct injection scheme) and to design the contacting apparatus and determine volumes of water required to effect disposal in a sour water disposal scenario. Anodier approach is to solubilize acid gas into light hydrocarbon solvent (taking advantage of high solubility of acid gas into light hydrocarbon solvent), and subsequently, use die light hydrocarbon solvent containing acid gas into die depleted hydrocarbon reservoir as a miscible flood enhanced oil recovery (EOR) tedmique. Experimental tests and results of various processes are discussed in this paper. In addition, advantages and disadvantages of all diese options are also discussed. Characteristics of Acid Gas Streams A summary of basic characteristics of acid gas components are summarized in Table 1.6.7 As seen in the table, bodt gases have diatomic structme and exhibit high propensity for solubilizing in both aqueous and hydrocarbon solutions, a fact which can be used to our advantage in some disposal operations. Composition ofdte injected acid gases can vary widely and is a direct function of the acid gas content of the oils/gases which are acting as the feedstocks for the sweetening process. In general, most acid gas blends contain at least 4Q8/. H.,S and often dte fraction ofHzS increase and after each compression stage die gas is cooled. Initially, die water holding capability of die gas decreases from stage to stage, until d1e minimum water holding capacity is reached. Ifdle condensed water is removed at this point. the gas will be undersaturated widl water throughout die rest of compression. Stainless steel will not be required in the compressors or coolers after die second last stage. If die temperature of die compressed gas does not drop to the new water saturation temperature in the pipeline or wellbore, dehydration can be eliminated and stainless steel materials and methanol injection will not be necessary. It is understood that dehydration may not be completely eliminated due to a particular set of conditions, for example in an extremely cold climate, die experimental data will still be beneficial. The operator will know the inlet water content and the conditions of the lowest water solubility of die system. The glycol contactor tower, regenerator and circulati

Designing an optimized injection strategy for acid gas disposal without dehydration

Abstract: The economics of recovering sulfur from sour natural gas have become unfavorable for small fields. Hydrocarbon producing companies require a cost effective yet environmentally sound alternative method to deal with acid gas. Compressed acid gas reinjection into producing, depleted or non-producing formations has emerged as a viable alternative to traditional sulfur recovery. Most injection schemes include dehydration facilities to remove the saturated water from the gas, preventing corrosion and hydrate formation. An alternative, less costly approach is to keep the water in the vapor phase throughout the injection circuit, eliminating the need to dehydrate. To design an optimized injection strategy, determination of thermodynamic and physical properties such as water content, dewpoint, bubble point, hydrate conditions and density of the acid gas is necessary. Experiments were conducted to determine properties of an acid gas containing a nominal 10% H{sub 2}S with remaining 90% CO{sub 2} and a minor amount of methane. Results indicate that the acid gas can be cooled between compression stages to 40 C (104 F) without entering the two phase region. For an injection pressure of 17,700 kPa (2,567 psia), dehydration is not required to cool the compressed gas to 8 C (46 F) without hydrate formation ormore » corrosion problems. At 9,000 kPa (1,305 psia) the gas can be safely cooled to {minus}2 C (28 F).« less

Production of formaldehyde from CH4 and H2 S

Abstract: A method wherein a sour natural gas stream can be treated to produce primarily carbon monoxide from methane, and the carbon monoxide and hydrogensulfide are reacted to produce methyl mercaptans, (primarily methanethiol (CH 3 SH) and a small amount of dimethyl sulfide (CH 3 SCH 3 )). The methyl mercaptans preferably are passed in contact with a catalyst comprising a supported metal oxide or a bulk metal oxide in the presence of an oxidizing agent and for a time sufficient to convert at least a portion of the methyl mercaptan to formaldehyde (CH 2 O), and sulfur dioxide (SO 2 ).

Effect of Alloy Nickel Content vs. PREN on the Selection of Austenitic Oil Country Tubular Goods for Sour Gas Service

Abstract: Traditionally, in the selection of Oil Country Tubular Goods (OCTG) for sour gas service, Corrosion Resistant Alloys (CRA`s) are screened first by their pitting resistance equivalent number (PREN) and then by environmental cracking data generated in sour brine environments. The theory is that a pit occurs first, which provides a stress-riser for initiation of anodic chloride stress corrosion cracking (KC). Among the primary CRA`s currently used in the cold worked condition for OCTG in sour gas wells are alloy 825 (UNS N08825) and alloy 28 (UNS N08028). While alloy 28 has a somewhat higher PREN than alloy 825, alloy 825 has a significantly higher nickel content. Slow strain rate (SSR) tests conducted in severe sour brine environments showed that the higher nickel content of alloy 825 results in better stress corrosion cracking resistance than that exhibited by alloy 28. The effect of nickel content on chloride SCC resistance of austenitic alloys was originally reported by H.R. Copson in 1959. This suggests that in some cases for austenitic alloys, the nickel content of the CRA may be more important than the PREN in OCTG selection.

Solubility of acid gases in a mixed solvent

Abstract: The solubility of hydrogen sulphide and carbon dioxide and their mixtures has been measured at 40/sup 0/ and 100/sup 0/C in a mixed solvent consisting of 20.9 wt% (2.0 M) MDEA (methyldiethanolamine), 30.5 wt% sulfolane, and 48.6 wt% water. The results have been compared with those for aqueous 2.0 M MDEA and an analogous mixed solvent, containing AMP (2-amino-2-methyl-1-propanol), which are available in the literature. At solution loadings less than 1 mol acid gas/mol MDEA, the solubility of the acid gas was lower in the mixed solvent that in the corresponding aqueous MDEA solvent; at solution loadings greater than 1 mol acid gas/mol MDEA, the reverse was true. At all loadings and at both temperatures studied, the mixed MDEA solvent absorbed equal or lesser quantities of acid gas than the comparable mixed AMP solvent. However, the shapes of the solubility curves show that the mixed MDEA solvent would be a better choice for certain industrial applications. These data were used to modify the solubility model of Deshmukh and Mather to account for the mixed solvent effects on the system thermodynamics. Results show that the model is useful as a first approximation in predicting acid gas solubilities; agreement with experiment wasmore » generally found to be within +-15%.« less

Modeling of gas absorption accompanied by chemical reaction in downflow co-current packed columns

Abstract: A mathematical model is presented for gas absorption accompanied by chemical reaction in downflow cocurrent packed columns. The model incorporates an axial dispersed plug flow for the bulk gas and dynamic liquid phases and a Fickian type equation for the stagnant liquid phase. The reaction is considered to be occurring in both the dynamic and stagnant liquid phases. Numerical simulations have been carried out to investigate the effect of various parameters of practical significance for absorption of CO2 from air into an alkaline solution of NaOH. The results of the numerical simulation show that the axial dispersion in the liquid phase do not affect the gas phase concentration profile, while dispersion in the gas phase affects both the liquid and gas phase concentration profiles. Increase in liquid and gas phase Peclet number, Reynolds number and the Stanton number results in enhanced absorption. The effect of dimensionless reaction rate constant K∗ R is only pronounced for values of K∗ R < 100. ...

Gas treating alternatives for LNG plants

Abstract: This paper covers the various gas treating processes available for treating sour natural gas to specifications required for LNG production. The LNG product specification requires that the total sulfur level be less than 30--40 ppmv, the CO{sub 2} level be less than 50 ppmv and the water level be less than 100 ppmv to prevent freezing problems in the LNG cryogenic column. A wide variety of natural gas compositions are encountered in the various fields and the gas treating process selection is dependent on the type of impurities present in the gas, namely, levels of H{sub 2}S, CO{sub 2}, mercaptans and other organic sulfur compounds. This paper discusses the implications various components in the feed to the LNG plant can have on process selection, and the various treating processes that are available to condition the gas. Process selection criteria, design and operating philosophies are discussed. An economic comparison for two treating schemes is provided.

Partial oxidation method of liquid hydrocarbon fuel or solid carton-containing fuel aqueous slurry

Abstract: A partial oxidation process for the production of a stream of cooled and cleaned synthesis gas, reducing gas, or fuel gas substantially free from entrained particulate matter and slag. The hot raw gas stream from the partial oxidation gas generator is quench cooled with deaerated grey water in a quench tank to produce black quench water or cooled in a radiant and/or convection cooler. The cooled gas is scrubbed with deaerated grey water in a scrubbing zone to remove all of the entrained particulate matter and to produce black scrubbing waters. The black water is resolved in a flashing zone and reused by flashing it in two or three flash stages connected in series and separating the overhead flash vapors comprising vaporized grey water and sour gas from the bottoms comprising concentrated black water. The flash vapors from the first flash stage are used to heat a stream of deaerated grey water being recycled to the quench tank and gas scrubbing zone or to the gas scrubbing zone. The concentrated black water from the flashing zone is thickened in a clarifier and then filtered to produce filter cake which may be burned and grey water filtrate. The flash vapors from the second flash stage and optionally steam are introduced into a deaerator to strip dissolved oxygen from incoming make-up water, grey water condensate, and grey water filtrate. In another embodiment of the process, the flash zone comprises three flash stages.

Advancements in treating subquality natural gas using N-formyl morpholine

Abstract: Process selection for gas treating is a complex phenomenon because processing requirements vary widely, and there are many gas sweetening solvents that are available to meet the requisite specification. Over the past few years, the Institute of Gas Technology (IGT) and Krupp Uhde GmbH (KU) have been conducting research on a physical solvent N-Formyl Morpholine (NFM) for treatment of subquality natural gas because of its advantages of lower energy consumption, higher CO{sub 2}/H{sub 2}S gas loadings, selective absorption of CO{sub 2}/H{sub 2}S, and lower loss of valuable C{sub 1}-C{sub 6} hydrocarbons as compared with other commercial physical solvents. Field experiment studies form the 1 MMscfd pilot plant unit operating at Shell`s Fandango facility confirms NFM as a cost-effective gas treating solvent. To date, a total of 78 tests using Koch`s random, high capacity and high-efficiency structured packing have been completed. These field experiments were conducted at wellhead conditions at 1,000 psig using slipstream from the Shell plant containing sour gas concentrations up to 43 mol % CO{sub 2}. These data, when used in a sophisticated process simulation, predicted a minimum of 40% operating cost savings depending upon sour gas concentration. This paper explains the development of NFM technology with resultsmore » from laboratory and field tests. This paper also discusses case studies pertaining to NFM application to retrofits, as well as new plants. Furthermore, this paper illustrates the scaling-up calculations from field test investigations. The potential of mixed solvent -- NFM and morpholine additives -- will also be discussed for increased acid gas loading, reduced circulation rate and column size. This emerging technology is the product of extensive research by IGT and is commercially available through KU for gas treating applications.« less

Stopping a Water Crossflow in a Sour Gas Producer Well

Abstract: Lacq is a sour-gas field in southwest France. After maximum production of 774 MMcf/D in the 1970`s, production is now 290 MMcf/D, with a reservoir pressure of 712 psi. Despite the loss of pressure, production is maintained by adapting the surface equipment and well architecture to reservoir conditions. The original 5-in. production tubing is being replaced with 7-in. tubing to sustain production rates. During openhole cleaning, the casing collapsed in Well LA141. The primary objective was to plug all possible hydraulic communication paths into the lower zones. The following options were available: (1) re-entering the well from the top and pulling the fish before setting cement plugs; (2) sidetracking the well; and (3) drilling a relief well to intercept Well LA141 above the reservoirs. The decision was made to start with the first option and switch to a sidetrack if this option failed.

Production of formaldehdye from ch4 and h2s

Abstract: A method wherein a sour natural gas stream can be treated to produce formaldehyde from methane and methyl mercaptans, (primarily methanethiol (CH3SH) and a small amount of dimethyl sulfide (CH3SCH3)) from hydrogen sulfide, and the methyl mercaptans preferably are passed in contact with a catalyst comprising a supported metal oxide or a bulk metal oxide in the presence of an oxidizing agent and for a time sufficient to convert at least a portion of the methyl mercaptan to formaldehyde (CH2O), and sulfur dioxide (SO2).

Effect of grain size on stress corrosion cracking resistance of alloy G-3 (UNS N06985) OCTG in sour gas environments

Abstract: Limited corrosion data exists on the effect of grain size on the stress corrosion cracking (SCC) resistance of Oil Country Tubular Goods (OCTG) to sour gas environments. Among the primary Corrosion Resistant Alloys (CRA`s) currently used in the cold worked condition for OCTG in sour gas wells is alloy G-3 (UNS N06985). Slow strain rate (SSR) tests conducted in a severe sour brine environment representative of Mobile Bay type conditions showed that the grain size of alloy G-3 OCTG has no discernible effect on stress corrosion cracking resistance. Also, no effect of grain size on intergranular attack (IGA) susceptibility was observed in the Streicher Test, ASTM Standard Test Method G28A.

Use of cobalt(II) phthalocyanines in oxidation of hydrogen sulfide solutions

Abstract: Catalytic activities of different catalysts, derivatives of cobalt(II) phthalocyanine, are compared in liquid-phase oxidation of hydrogen sulfide with oxygen at various pH values of the reaction medium.