Showing papers on "Sour gas published in 2010"

Process Development, Simulation, and Industrial Implementation of a New Coal-Gasification Wastewater Treatment Installation for Phenol and Ammonia Removal

Abstract: Coal-gasification wastewater poses serious problems in the Lurgi process. It cannot be easily purified, as the high pH value of the wastewater limits the dephenolization efficiency of extraction. This work proposes a new process to remove ammonia and sour gas in order to reduce the pH value of the wastewater from 9 to below 7, and next to remove phenol with solvent extraction under acidic conditions. This new process consists of a wastewater stripper with side-draw to remove ammonia and sour gas, an extractor to remove phenol, and two distillation columns to recover extractant. Process simulation was conducted to study the performance of the new process and to perform a detailed design. The complex multicomponent system NH3−CO2−H2S−NaOH−phenol−H2O was analyzed when simulating the wastewater stripping. The new process has been successfully implemented in an industrial installation for coal-gasification wastewater treatment with a capacity of 2000 tons/day. Satisfactory agreement was obtained between the si...

Experimental investigation on the solubility and initial rate of absorption of CO2 in aqueous mixtures of methyldiethanolamine with the ionic liquid 1-butyl-3-methylimidazolium tetrafluoroborate

Abstract: In this paper we present the results of the initial absorption rate and solubility of CO2 in aqueous 4 M methyldiethanolamine (MDEA) mixed with various concentrations of 1-butyl-3-methylimidazolium tetrafluoroborate ([bmim][BF4]) at (303, 313, 323, and 333) K. All experiments were carried out at low partial pressures of CO2, below 110 kPa. The results of this research suggested that the presence of a low concentration of [bmim][BF4] in aqueous 4 mol·L−1 MDEA has no significant effect on the mixture loading capacity, but increased the initial absorption rate. The amine CO2 loading capacity showed a significant decrease in the presence of high concentrations of ionic liquid in the mixture.

Systems and methods for removing heavy hydrocarbons and acid gases from a hydrocarbon gas stream

Abstract: A system for removing acid gases from a sour gas stream is provided. The system includes an acid gas removal system and a heavy hydrocarbon removal system. The acid gas removal system receives the sour gas stream and separates the sour gas stream into an overhead gas stream comprised primarily of methane, and a bottom acid gas stream comprised primarily of acid gases such as carbon dioxide. The heavy hydrocarbon removal system may be placed upstream or downstream of the acid gas removal system or both. The heavy hydrocarbon removal system receives a gas stream and separates the gas stream into a first fluid stream comprising heavy hydrocarbons and a second fluid stream comprising other components. The components of the second fluid stream will depend on the composition of the gas stream. Various types of heavy hydrocarbon removal systems may be utilized.

Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide

Abstract: A system for removing acid gases from a raw gas stream includes an acid gas removal system (AGRS) and a sulfurous components removal system (SCRS). The acid gas removal system receives a sour gas stream and separates it into an overhead gas stream comprised primarily of methane, and a bottom acid gas stream comprised primarily of carbon dioxide. The sulfurous components removal system is placed either upstream or downstream of the acid gas removal system. The SCRS receives a gas stream and generally separates the gas stream into a first fluid stream comprising hydrogen sulfide, and a second fluid stream comprising carbon dioxide. Where the SCRS is upstream of the AGRS, the second fluid stream also includes primarily methane. Where the SCRS is downstream of the AGRS, the second fluid stream is principally carbon dioxide. Various types of sulfurous components removal systems may be utilized.

Computational Study of Hexamethylguanidinium Lactate Ionic Liquid: A Candidate for Natural Gas Sweetening

Abstract: Considering the technological and economical importance of natural gas sweetening, new methods have to be developed to replace the aqueous amine processes currently used in most of the gas processing industry, with the objective of improving the treatment of sour gases, avoiding the problems arising from the amine technologies to fulfill the present technological, economical, and environmental requirements of the natural gas industry. Ionic liquids have been proposed in the literature as a suitable alternative for sour gas capture through physical/chemical absorption mechanisms. Guanidinium/lactate ionic liquids have showed adequate absorption ability, leading to low Henry’s constants, for both CO2 and H2S. Moreover, this ionic liquid shows very favorable economical, technological, and environmental properties that would make it suitable for sour gas absorption on a large scale. Nevertheless, the mechanism of the interaction between the considered acid compounds and the ionic liquid is still not fully und...

Gas−Liquid Equilibrium Data for a Mixture Gas of Sulfur Dioxide + Nitrogen with Ethylene Glycol Aqueous Solutions at 298.15 K and 123.15 kPa

Abstract: Isothermal gas−liquid equilibrium (GLE) data have been measured for the system SO2 + N2 + ethylene glycol (EG) + water at 298.15 K and 123.15 kPa and SO2 partial pressures in the range of (0 to 120) Pa. Measurements were carried out by a saturation method using a glass absorption apparatus, which was controlled at constant temperature by a thermostatic circulation bath with a Beckmann thermometer. The GLE data were obtained with relative uncertainties within ± 3.5 % for SO2 concentration in the gas phase and ± 0.6 % for SO2 concentration in the liquid phase. The measurement showed that the addition of water to EG enhanced the solubility of SO2 compared with pure EG and that the 80 % volume fraction of EG in ethylene glycol + water solution is a more reasonable composition used as the desulfurization solution. The results of this work can be used to provide important GLE data for the design and operation of the absorption and desorption process in flue gas desulfurization (FGD) with potential industrial ap...

Method and apparatus for adjustably treating a sour gas

Abstract: A feed gas comprising CO2, H2S and H2 is treated to produce an H2-enriched product and an H2S-lean, CO2 product. The feed gas is separated to provide the H2-enriched product and a stream of sour gas. The stream of sour gas is divided into two parts, one of which is processed in an H2S removal system to form one or more streams of sweetened gas, and the other of which bypasses the H2S removal system, the stream(s) of sweetened gas and the sour gas bypassing the H2S removal system then being recombined to form the H2S-lean, CO2 product gas. The division of the sour gas between being sent to and bypassing the H2S removal system is adjusted responsive to changes in the H2S content of the sour gas, so as to dampen or cancel the effects of said changes on the H2S content of the H2S-lean, CO2 product gas.

Sour gas treatment process

Abstract: The disclosure relates to a process for treating a gas mixture containing carbon dioxide and hydrogen sulphide, including the following steps: deacidificating the gas mixture by bringing the gas mixture into contact with a first lean absorbent solution stream, delivering a deacidified gas mixture, and a first rich absorbent solution stream; regenerating the first rich absorbent solution stream, delivering the first lean absorbent solution stream and a sour gas stream; distillating the sour gas stream, delivering a first carbon-dioxide-rich stream and a hydrogen-sulphide-rich stream; purifying the first carbon-dioxide-rich stream by bringing the first carbon-dioxide-rich stream into contact with a second lean absorbent solution stream, delivering a second carbon-dioxide-rich stream and a second rich absorbent solution stream, the molar concentration of carbon dioxide in the second carbon-dioxide-rich stream being greater than the molar concentration of carbon dioxide in the first carbon-dioxide-rich stream. The disclosure also relates to an installation designed to implement this process.

Process and apparatus for reducing the concentration of a sour species in a sour gas

Abstract: A process and apparatus for reducing a concentration of sour species in a gas to a predetermined residual concentration is provided. The process involves cooling the sour gas in a manner to produce a mixture of solid and/or liquid sour species and a vapour containing gaseous hydrocarbons and a residual amount of sour species. A cooled gas is separated from the mixture. The residual concentration of sour species in the cooled gas is then determined. When the residual concentration of sour species in the cooled gas is above the predetermined concentration, the cooled gas is compressed and the preceding process is repeated until the residual concentration of sour species in the cooled gas is at or below the desired concentration.

Sour gas and acid natural gas separation membrane process by pre removal of dissolved elemental sulfur for plugging prevention

Abstract: Methods for removing sulfur from a gas stream prior to sending the gas stream to a gas separation membrane system are provided. Two schemes are available. When the sulfur content is high or flow is relatively high, a scheme including two columns where one tower is regenerated if the sulfur concentration exceeds a preset value can be used. When the sulfur content is low or flow is relatively low, a scheme including one column and an absorption bed.

Determination of the Critical Pitting Temperature of Martensitic and Supermartensitic Stainless Steels in Simulated Sour Environments Using Electrochemical Noise Analysis

Abstract: The use of corrosion-resistant alloys (CRA) has allowed oil and gas operations in environments where carbon and low-alloy steels would have otherwise corroded too quickly, increasing downt...

Mechanism of annular fluid thermal expansion pressure in HTHP sour gas wells

Abstract: In HTHP sour gas wells,over-high pressure in annulus will affect normal productionOnce it exceeds the allowable limit,potential safety hazards will be evokedIn view of high pressure problem resulting from thermal expansion of annulus fluid due to the temperature increase during the production period,a calculation model was established for that pressure in HTHP sour gas wellsAnd case studies were then madeThe results show that the heat-induced annulus pressure can cause failure in production pipe string,posing threat to safe productionSo when doing casing program planning,casing strength designing,and optimal annulus fluid determining,we had better to reduce the production-heat-induced annulus pressure and to manage the annulus pressure effectively while maintaining normal operation system,so as to ensure long-term safe production in HTHP sour gas wells

Carbon Disulfide Production via Hydrogen Sulfide Methane Reformation

Abstract: Carbon disulfide is widely used for the production of viscose rayon, rubber, and other organic materials and it is a feedstock for the synthesis of sulfuric acid. The objective of this paper is to analyze possibilities for efficient production of CS2 from sour natural gas reformation (H2SMR) (2H2S+CH4 =CS2 +4H2) . Also, the effect of H2S to CH4 feed ratio and reaction temperature on carbon disulfide production is investigated numerically in a reforming reactor. The chemical reaction model is based on an assumed Probability Density Function (PDF) parameterized by the mean and variance of mixture fraction and β-PDF shape. The results show that the major factors influencing CS2 production are reactor temperature. The yield of carbon disulfide increases with increasing H2S to CH4 feed gas ratio (H2S/CH4≤4). Also the yield of C(s) increases with increasing temperature until the temperature reaches to 1000°K, and then due to increase of CS2 production and consumption of C(s), yield of C(s) drops with further increase in the temperature. The predicted CH4 and H2S conversion and yield of carbon disulfide are in good agreement with result of Huang and TRaissi. Keywords—Carbon disulfide, sour natural gas, H2SMR, probability density function.

Acid Gas Processing and Mercaptans Removal

Abstract: This chapter discusses acid gas processing. Acid gases in a refinery are carbon dioxide (CO 2 ) and hydrogen sulphide (H 2 S). Sour gas is the gas containing sulfur compounds, such as mercaptans and carbonyl sulphide (COS). Gas with only CO 2 is called sweet gas. Although the main gas treatment processes emit CO 2 and H 2 O, CO 2 is now considered an undesired product due to its role in global warming. CO 2 is a corrosive material, non-combustible and captures solar radiation if released into the atmosphere therefore, warming the earth's atmosphere. H 2 S is a highly toxic, flammable gas with an auto-ignition temperature of 292 o C (500 o F). H 2 S is 1.18 times heavier than air. Therefore, it may accumulate in dangerous concentrations in drains, valve pits, vessels and tanks. A hydrogen sulphide concentration must be less than 6 mg/m3 (43 ppm) to prevent the effect of corrosion in process equipment. Most industrial personnel gas detectors are set to 20 ppm of H 2 S in air as a limit for the escapemode from an area. This chapter also discusses and mercaptans removal in refineries. The predominant sulfur compounds in refinery products that usually have an unpleasant smell are mercaptans. They are corrosive and disturb the fuel stability due to gum formation. The principle of mercaptans removal is oxidation. The mercaptan oxidation is called MEROX process.

Dehydration of Acid Gas Prior to Injection

Abstract: Publisher Summary Acid gas is a mixture of hydrogen sulfide and carbon dioxide with a small amount of lower molecular weight hydrocarbons, mainly methane. Acid gas is most often produced in sour natural gas sweetening units, during regeneration of the sweetening chemical, usually an amine. Acid gas liberated from rich amine leaves the amine regeneration tower at a low pressure, typically below 200 kPa, and at about 50°C, the typical temperature downstream of the regeneration tower overhead condenser. In addition, the acid gas is saturated with water. This is not produced water, which contains dissolved salts, which can cause additional problems but rather this is condensed water that should contain virtually no dissolved solids. If acid gas is to be injected into a subsurface formation such as an aquifer or a depleted reservoir, it must be compressed and sent to an injection well through a pipeline. Water present in acid gas can contribute to corrosion of the compression equipment and the pipeline, and it may facilitate hydrates formation. All main constituents of acid gas: H 2 S, CO 2, and methane, are hydrate formers. Hydrates can form in acid gas without the presence of free water; however free water is required in the acid gas to cause corrosion of carbon steel. It is recommended to keep the relative water saturation of the acid gas mixture considerably below 100% in order to avoid condensation of water in the piping, facilities, pipeline or well.

Hydrogen and carbon black production from thermal decomposition of sub-quality natural gas

Abstract: The objective of this paper is computational investigation of the hydrogen and carbon black production through thermal decomposition of waste gases containing CH 4 and H 2 S, without requiring a H 2 S separation process. The chemical reaction model, which involves solid carbon, sulfur compounds and precursor species for the formation of carbon black, is based on an assumed Probability Density Function (PDF) parameterized by the mean and variance of mixture fraction and β-PDF shape. The effects of feedstock mass flow rate and reactor temperature on hydrogen, carbon black, S 2 , SO 2 , COS and CS 2 formation are investigated. The results show that the major factor influencing CH 4 and H 2 S conversions is reactor temperature. For temperatures higher than 1100° K, the reactor CH 4 conversion reaches 100%, whilst H 2 S conversion increases in temperatures higher than 1300° K. The results reveal that at any temperature, H 2 S conversion is less than that of CH 4 . The results also show that in the production of carbon black from subquality natural gas, the formation of carbon monoxide, which is occurring in parallel, play a very significant role. For lower values of feedstock flow rate, CH 4 mostly burns to CO and consequently, the production of carbon black is low. The results show that the yield of hydrogen increases with increasing feedstock mass flow rate until the yield reaches a maximum value, and then drops with further increase in the feedstock mass flow rate.

System and method for sour gas well testing

Abstract: The invention provides a method of testing sour natural gas by a) removing H2S from the gas stream, b) converting H2S to elemental sulfur, and c) recovering elemental sulfur. The invention also provides a substantially mobile system for testing sour natural gas including vehicles allowing the equipment to be operated on surfaces such as the flat beds of trailers. The system features equipment that may be mounted within one or more support structures situated on a mobile vehicle, such as, for instance the flat bed of a trailer. The one or more support structures hold each piece of equipment substantially fixed in place on the vehicles. Each surface such as the flat bed of a trailer may carry one, two or more pieces of equipment. The equipment may include, for instance, an air or oxygen compressor, a knockout vessel, a gas heater, an air heater, a cooler, a molten sulfur separator and a thermal oxidizer.

Stabilization and remote recovery of acid gas fractions from sour wellsite gas

Abstract: A method for the recovery of hydrogen sulphide and other acid gas fractions from sour wellsite gas in hydrocarbon production is provided. The selected acid gas fractions are absorbed into a noncorrosive and transportable solvent solution at the weilsite, the rich solvent solution being transported to a central plant location where it is desorbed from the solvent solution for further handling or processing. The lean solvent solution can then be recycled. Multiple acid gas fractions could be recovered from the sour gas in question using a single appropriate solvent solution. Carbon dioxide could be absorbed and desorbed at the wellsite rather than at the central plant location. Clean gas is yielded at the wellsite for downstream processing or sale.

ATS tail gas treating process for SRU and SWS off gases

Abstract: The present invention relates to a system and process utilizing ammonium thiosulfate solution (ATS) as the primary liquid absorption agent that is re-circulated through an SO2 Contactor/Absorber for high efficiency contacting and absorption of sulfur dioxide, SO 2 from a combustion gas stream generated by incineration of a Claus Sulfur Recovery Unit (SRU) off gas stream (often referred to as a Claus tail gas stream) and also additional SO 2 generated from incineration of additional sulfur containing streams. ATS is also re-circulated through a separate H2S Contactor/Absorber for absorption of and reaction with a Sour Water Stripper (SWS) off gas stream and additional H2S-Acid Gas (A.G.) streams to produce additional concentrated ATS. The process and equipment also provides the ability to readily switch between using ATS and ABS as the primary absorbent solution for SO 2 absorption, depending upon the concentration of SO 2 in the off gas feed streams.

Simulation and assessment on leakage hazard from gas sweetening unit of sour gas processing plant in complex terrain

Abstract: Massive release of sour gas and dispersion of fatal hydrogen sulfide brought about by gas sweetening unit leakage are a major threat to the safety of sour gas processing plant.By analyzing the leakage and atmospheric conditions,the scene of accident,caused by the leakiness of gas sweetening unit,were determined.Based on large eddy simulation of turbulent flows,H2S dispersion in complex terrain was simulated.The peak time for accident was estimated,hazard regions were ranked and the influences of terrain on dispersion could be summarized as spatial obstacle,channeling and aggregation.Dose-response relationship for acute H2S poisoning was used to assess the cumulative effects of H2S on the public and calculate the lethal percentages.The maximum distances,downwind deflection angles,maximum widths and areas of the lethal regions were obtained.The application in one sour gas processing plant in mountainous area shows that the accident will cause high death risk around the plant and adjacent road,and not lead to mortality in the nearby residential area and planned highway.Based on the features of the accident,recommendations to establishing emergency planning zone,taking immediate shelter and implementing priority relief are suggested for emergency response.