Showing papers on "Sour gas published in 1991"

Effect of Elemental Sulfur on Corrosion in Sour Gas Systems

Abstract: The corrosive interaction of wet elemental sulfur with construction materials is reviewed, emphasizing effects of alloy composition (carbon steels, ferritic steels, austenitic steels, ferr...

Iron Control in West Texas Sour-Gas Wells Provides Sustained Production Increases

Abstract: Permian Basin operators have recorded sustained production increases in oil wells by preventing precipitation of iron sulfide and other sulfur-containing species. This improvement has resulted largely from cleaning out tubing before acidizing and from preventing the precipitation of ferrous sulfide and the formation of elemental sulfur by simultaneous use of iron chelants and sulfide-control agents. Previously used methods gave only temporary production increases that terminated when iron dissolved by the stimulation acid reprecipitated in the pay zone and damage the formation after the stimulation acid was spent. This paper describes a method to optimize iron sulfide control, methods to minimize reprecipitation, and case histories from the Permian Basin that show improved methods to control iron in sour-well environments.

The applicability of duplex stainless steels in sour environments

Abstract: Very low tolerable partial pressures of H2S (pH2S) have been reported for duplex stainless steels in sour environments. However, such steels resist stress corrosion cracking (SCC) in sour ...

Sulfur recovery process for ammonia-containing feed gas

Abstract: Ammonia-containing sour gas is combusted at high flame temperature with at least 90 percent purity oxygen in an externally cooled combustor, the ammonia-free product is cooled, then, in conjunction with additional acid gas which does not contain ammonia, is passed to a Claus furnace wherein less than one-third of the hydrogen sulfide is combusted with oxygen enriched air enabling boosting sulfur recovery in a Claus plant without detrimental effects on catalyst life, furnace refractories and pressure drops.

Method of treating a spent caustic stream from a sour water stripper to reduce the sulfide content thereof

Abstract: This invention relates to a method of reducing the concentration of sulfides in an aqueous system by first treating the aqueous system with hydrogen peroxide to lower the sulfide concentration to approximately 300 ppm, or less, then subsequently treating the aqueous system with chlorine dioxide to further reduce the sulfide concentration to a desirable level. The method of the invention is capable of reducing the sulfide content of the treated aqueous system to as low as tenths of a part of sulfide per million parts of sour water.

Gas-desulfurization plant handles wide range of sour gas compositions

Abstract: The Nederlandse Aardolie Maatschappij B.V. (NAM) gas desulfurization facilities at Emmen treat a natural gas feed containing H{sub 2}S, CO{sub 2}, and mercaptans, to tight pipeline specifications. This paper reports on the highly selective Sulfinol-M solvent which enables the plant to treat natural gases with a CO{sub 2}/H{sub 2}S ratio as high as 25:1, while producing an acid- gas feed suitable for a conventional Claus unit. To help meet the stringent environmental regulations, an integrated Shell Claus off-gas treating (SCOT) unit achieves an overall sulfur recovery of better than 99.8%.

Investigation of U. S. natural gas reserve demographics and gas-treatment processes. Topical report

Abstract: The report presents the results of a study undertaken to consolidate and analyze publicly available information on (1) the quantity and composition of U.S. natural gas reserves; and (2) gas treatment processes. This was done in order to determine the amount of sour gas treated and the fate of that material. Natural gas production statistics (Oil Gas Journal, 1987) and Bureau of Mines natural gas analysis data (1917-1987) were compiled in an in-house database. Computer-generated plots showing the demographics of natural gas reserves and its components were produced. Data from the 1982 API Gas Plant Survey on characteristics of natural gas processed in the U.S. and applications of gas sweetening and sulfur recovery processes were also summarized and observations made. An effort was made to obtain additional information on the hydrogen sulfide content of natural gas through telephone contacts with numerous government and private industry sources.

Process for converting carbon disulfide to hydrogen sulfide in hydrogen sulfide/carbon disulfide mixtures

Abstract: A process for converting carbon disulfide (CS2) to hydrogen sulfide (H2 S) in mixtures of H2 S and CS2 is provided. The H2 S/CS2 mixture is combined with water to form a hydrolysis feed mixture. The hydrolysis feed mixture is passed through a hydrolysis reactor containing e.g., an alumina-based catalyst, wherein a substantial portion of the CS2 is converted to additional H2 S. A vapor product comprising H2 S, CO2, unreacted H2 O, unconverted CS2 and sulfur is formed by the hydrolysis reaction. The vapor product is cooled to form a H2 S/CO2 vapor phase and a sour water condensate phase. The H2 S/CO2 vapor phase is separated from the sour water condensate phase and subsequently recovered. The sour water condensate phase, which contains small amounts of solid sulfur particles, is optionally then combined with additional CS2 and decanted to form a sulfur-free sour water layer and a CS2 layer containing dissolved sulfur. The sour water layer is recycled and combined with the original H2 S/CS2 mixture. The CS2 layer is recycled to a sulfur removal device to remove the sulfur dissolved in the CS2.

Application of Alkylnaphthalene Absorption Oil as a Sulfur Solvent in Sour-Gas Wells

Abstract: This paper reports on elemental sulfur which is soluble in sour gas and often precipitates in sour-gas wells during production. Prevention of sulfur deposition in the production equipment requires the application of a sulfur solvent. An aqueous alkaline solvent is inadequate at increasing formation-water inflow resulting in severe carbonate precipitation. The new solvent is based on a mixture of alkylnaphthalenes diluted in a mineral oil. Both can combine physically with the precipitated sulfur. The performance of the solvent during circulation, its regeneration, and its behavior in corrosion inhibition is outlined. Application of this solvent improved the production of the treated sour-gas wells.

A New Age-Hardenable Corrosion Resistant Alloy for Deep Sour Gas Well Service

Abstract: Alloy 725 (UNS N07725) is a highly corrosion resistant alloy capable of being age-hardened to 0.2% yield strengths from 115 to 140 ksi (793 to 965 MPa), while maintaining a high level of ductility and toughness1 . As alloy 725 is an austenitic nickel base alloy which is strengthened by precipitation of a gamma double-prime (y”) during aging, large section sizes can achieve uniform hardening throughout the cross section. The alloy is resistant to pitting and stress corrosion cracking (SCC) in Deep Sour Gas Well environments containing NaCl, H2S and S at temperatures up to about 450” to 500°F (232” to 26O”C), and to sulfide stress cracking (SSC) in the NACE TM-0177 environment. Alloy 725 also exhibits excellent corrosion resistance to other commercially significant environments, such as seawater and mineral acids.

Catalyst and process for removal of sulphur compounds and nitrogen oxides from fluid streams

Abstract: The invention comprises a regeneratable catalyst that is capable of providing a reactive oxygen to partially oxidize sulphur-containing compounds to produce sulphur. It includes a method for removing sulphur compounds including both sulphur oxides and hydrogen sulphide from a fluid stream and decomposing such compounds to produce sulphur. Sour natural gas can be sweetened effectively by this invention, and sulphur can be prepared thereby. The catalyst is preferably formed by impregnating alkali metal sulfide and sulfide(s) or selenide(s) of metal(s) showing polyvalent and/or amphoteric character, e.g. Zn, etc. on a microporous type support (e.g., alumina). Its activity is sustained by exposure to a source of oxygen, such as air, oxygen sulphur dioxide or nitrogen peroxide and the like. A method is also described by which sulphur dioxide may be absorbed from flue gas and converted to sulphur, while higher oxides of nitrogen and carbon dioxide are being absorbed for subsequent recovery, utilizing a catalyst that has been conditioned by prior exposure to a reducing gas.

Testing and evaluation of corrosion-resistant alloys

Abstract: Results of autoclave and slow strain rate testing of highly alloyed materials in a simulated deep sour gas well environment are described. Some 825-type alloys and 25 Cr-50 Ni alloys failed by environmental cracking. The more corrosion-resistant alloys, such as alloy C-276, were immune to failure

Coal mon-fuel combustion thermal power plant having contamination preventing system and producing useful byproduct

Abstract: PURPOSE: To generate useful byproducts while preventing pollution by arranging a gypsum desulfurization device for generating useful aggregate and SO2 containing gas for gasifying coal by reducing the gypsum. CONSTITUTION: Flue gas from a boiler 16 is passed to a blue gas desulfurization device 13 so as to generate gypsum. The gypsum is supplied to a gypsum desulfurization device 20 together with a part of coal from a device 10 for gasification and for regulating coal and ash from the boiler 16, and a part of LBTU gas from sour gas eliminating device 12. Mixture of the gypsum and the coal is heated by means of burning operation of the LBTU gas so as to reduce the gypsum. Generated SO2 containing gas is returned to the device 10, and the coal is gasified together with replenished air. An aggregate generated from the device 20 is used for construction of a road or a building. Sulfur compound from the device 12 is converted into an elemental sulfur in a sulfur recovery device 14, and waste gas from the device 14 is treated by the device 13.

Composition for dissolving sulfur and process for its use

Abstract: A composition is disclosed for dissolving sulfur and preventing or removing sulfur plugs from sour gas and oil wells or other conduits through which sulfur bearing liquids flow which comprises a major proportion of a liquid or gaseous mercaptan, a minor proportion of a catalyst which is a substantially water-insoluble amine, and minor amount of an activator which is a compound of the formula: where R is hydrogen, alkyl, aryl or alkaryl and the alkyl moieties have from 1 to 24 carbon atoms, and x and y are independent values between 0 and 24 provided that x or y is at least 1; a method is also disclosed wherein said composition in an effective amount is injected into a conduit to prevent or remove sulfur plugging, and the composition containing dissolved sulfur is optionally recovered.

Analysis of Community Risk Resulting from Rupture of a Sour Gas Pipeline

Abstract: Natural gas pipelines present fire and explosion hazards to nearby communities. These hazards are compounded if significant amounts of hydrogen sulfide (H2S) are present in the gas. This paper presents the methodology and difficulties encountered in analyzing a long sour gas pipeline (H2S present) from an offshore field in southern California. A number of issues were studied in depth in order to present community hazards in the form of risk profiles. More specifically, these issues encompassed: the rate of gas released from a pipeline rupture; the value of parameters such as gas temperature and density as the gas flashes to atmospheric pressure; the failure frequency of the pipeline; the population distribution; the effect of varying weather conditions; toxic hazard levels; and such concerns as the impact of shielding, terrain and age of potential recipients. Some of these issues were particularly difficult to analyze. For example, the rupture rate for sour gas lines is highly correlated with the potential for internal corrosion, which is influenced by such factors as H2S and CO2 content in the gas stream. This problem is further influenced by other factors such as pipeline steel metallurgy and gas wetness. This study presents the approach taken to analyze the impact of the more important issues affecting the problem. Because most of the input parameters display a fair amount of uncertainty, the analysis places bounds on the results. An upper and lower bound on both casualties and fatalities is presented for the community risk profiles.

Process for removing hydrogen sulphide from a sour gas

Abstract: A process for the removal of hydrogen sulphide from a sour gaseous stream comprising feeding the sour gaseous stream to a reaction zone (4) containing an aqueous reactant solution; passing the gaseous stream and aqueous reactant solution concurrently upward through the reaction zone (4), the momentum of the gaseous stream being sufficient to provide and providing the principal motive force for the upward movement of the aqueous reactant solution, under conditions and for a time sufficient to remove hydrogen sulphide from the gaseous stream, and producing a purified gas, sulphur, and partially spent solution admixture; and passing the purified gas, sulphur, and partially spent solution admixture to a gas-liquid separation vessel (3) comprising an open separation zone (6) and a reservoir (8) in liquid flow communication with the entrance of the reaction zone (4).

On the Evaluation of Precipitation Hardening Alloy 625 For Use in the Production of Sour Gas

Abstract: Natural gas production from reservoirs with high partial pressures of H,S (i.e., sour) can economically be pursued using high strength, corrosion resistant alloys that have a high resistance to fracture and environmentally assisted cracking. For thick-walled components, development of age hardenable versions of Alloy 625 were required. Several of these have been evaluated in laboratory tests designed to reveal their suitability for use in the production of sour gas. While the compositions and processing steps of these alloys were quite similar, differences in fracture toughness and resistance to hydrogen embrittlement were observed. Background Information Corrosion resistant alloys (CRA's) have been used in oil and gas production equipment for many years. Earlier, these alloys were primarily used in valve stems and seats, choke internals, downhole safety and control devices applications where sealing surfaces are paramount and where even small amounts of corrosion could prevent proper operation. Acid gases, H,S and co,, in the production fluids promoted corrosion. A draft industry Recommended Practice [l] in the mid-60's listed the AISI-300 and 400 series stainless steels, the Monels, Alloy X-750, cold drawn Alloy 600, and the Stellites and Colmonoys as generally satisfactory. No processing restraints except for several specific limitations on hardness were advised. Occasional field cracking failures were reported. Inhibition remained the primary method of corrosion abatement and was tailored to protect the carbon and low alloy steel components in the wells, not the CRA's. In the early to mid-70's, two developments had a noteworthy impact on CRA usage. Firstly, the exploitation of very corrosive acid gas reservoirs challenged the available inhibitors for steel and forced the consideration of CRA casing and tubing. Alloy 625 (UNS N06625) was one of the three leading candidates for casing with high strength achieved by cold reduction. Age hardening of the cold worked pipe provided a small increment in strength. Superalloys 718,625 and Various Derivatives Edited by Edward A. Lmia The Minerals, Metals & Materials Society, 1991 761 The second development that influenced CRA usage was the adoption of metal-to-metal seals to replace elastomers for most of the prime sealing surfaces including pipe-to-pipe, hanger-to-hanger body spools, packers, and valve stems. In an all CRA system, inhibition is not used and the prevention of corrosion at seal surfaces becomes a more critical issue. Alloy 718 replaced Alloy X-750, because it had more corrosion resistance, in those applications hangers, packers, stems, etc. where the thick cross-sections prevented effective cold working to achieve the necessary strength. Attending its adoption, Alloy 718 carried stringent processing controls because high notch toughness was deemed desirable and alternate processing routes for this alloy exploited its creep rupture properties at the neglect of toughness. CRA's tailored to a particular field environment became an accepted materials selection practice by the 1980's. Corrosion resistance combined with high strength was more readily available in cold worked systems than in age hardened systems. It was recognized that an alloy with more corrosion resistance than Alloy 718 was needed for certain reservoirs in the development of the Mobile Bay, Alabama gas fields. Alloy 625 had the corrosion resistance, but the small increment of strength by aging could not assure the = 120 ksi (827 MPa) needed in a number of wellhead and downhole components. With this in mind, a directed effort was started to encourage a number of alloy suppliers to develop a new alloy or enhance the existing Alloy 625 to meet these needs. This paper presents the laboratory test results performed on candidate materials obtained from various suppliers in the form of bar stock with a relatively large cross-section intended for hanger, packer body, and wellhead component applications. They are offered in the hope that further development toward optimum performance will be pursued by interested parties. Materials Materials Evaluation Precipitation hardened (PH) Alloy 625 is a modification of Alloy 625 that permits strengthening by aging in significantly shorter times than can be achieved with Alloy 625. The strengthening occurs by the precipitation of 7\" (Ni,{Nb,Ti,Al)); little or none of y' (Ni,(Ti,Al,Nb)) is present [2,3]. Strengthening by precipitation hardening is preferred to the cold working of CRA's for the case of high strength, thick-walled products because it produces more uniform through-wall mechanical properties. Samples of age hardenable Alloy 625 were received from various vendors in solution annealed, solution annealed and aged conditions, or without any heat treatment. Samples of the solution annealed and without heat treatment were subjected to various heat treatments designed to achieve specific properties. Table 1 is a list of the compositions of the materials reported here. In general, the variables are C and \"hardener elements\" such as Nb, Ti, and Al. An earlier version of Alloy 625 was subjected to exploratory heat treatments and tested. The results are shown in Table 2. The desired aims of 120 ksi (827 MPa) yield and 40 ft-lbs Charpy impact values were met by specific heat treatments. However, the microstructure showed mixed grain size and \"necklace\" structure, and required long aging times. These results indicated that alloying modifications as well as heat treatment were necessary to achieve properties within reasonable aging cycles.