Showing papers on "Sour gas published in 1997"

Gas Souring by Thermochemical Sulfate Reduction at 140¡C: Reply

Abstract: Natural gas in the Permian-Triassic Khuff Formation of Abu Dhabi contains variable amounts of H2S. Gas souring occurred through thermochemical sulfate reduction of anhydrite by hydrocarbon gases. Sour gas is observed only in reservoirs hotter than a critical reaction temperature: 140°C. Petrographic examination of core from a wide depth range showed that the anhydrite reactant has been replaced by calcite reaction product only in samples deeper than 4300 m. Gas composition data show that only reservoirs deeper than 4300 m contain large quantities of H2S (i.e., >10%). At present-day geothermal gradients, 4300 m is equivalent to 140°C. Fluid inclusion analysis of calcite reaction product has shown that calcite growth only became significan at temperatures greater than 140°C. Thus, three independent indicators all show that 140°C is the critical temperature above which gas souring by thermochemical sulfate reduction begins. The previously suggested lower temperature thresholds for other sour gas provinces (80-130°C) derive from gas composition data that may not allow adequately either for the reservoir temperature history or for the migration of gas generated at higher temperatures into present traps. Conversely, published proposals for higher threshold temperature (180-200°C) derive from short duration experimental data that are not easily extrapolated to geologically realistic temperatures and time scales. Therefore, the temperature of 140°C derived from our study of the Khuff Formation may be th best estimate of temperature required for in-situ thermochemical sulfate reduction to produce the high H2S concentrations encountered in deep carbonate gas reservoirs.

Hydrogen-Induced Crack Growth Rate in Steel Plates Exposed to Sour Environments

Abstract: A mathematical model was proposed for determining the crack growth rate of hydrogen-induced cracking (HIC) in steel plates exposed to a sour gas. The model assumes that the extension of an embedded circular crack results from accumulation of internal hydrogen pressure that produces a rise of the stress intensity factor in excess of the plane strain fracture toughness of the steel with dissolved hydrogen. Upon crack extension, the volume of the crack cavity increases, and the pressure drops, causing the crack to arrest. As the cavity is filled again with hydrogen, the process is repeated. HIC experiments were conducted on API 5L-X52 steel plates, using ultrasonic inspection to measure crack sizes. Data from inspected sour gas pipelines were gathered and compared to the predicted crack growth rates. The model showed reasonable agreement with experimental results, which corresponded to the first stages of HIC growth. It failed to approximate values for large crack lengths found in pipelines after long exposure to sour gas. This suggested either that there were important crack delay processes or that the cracking criterion changed as the crack grew. These delay processes were related to the effect of metallurgical variables.

Linepipe and structural steel produced by high speed continuous casting

Abstract: A high strength, high toughness, low carbon/low manganese steel is provided that is further resistant to stepwise cracking and sulfide stress cracking. The steel can be produced by conventional or thin slab casting techniques using normal speeds, with low manganese segregation levels. The steels are excellent candidates for linepipe applications in severe sour gas service.

Acid gas injection eliminates sulfur recovery expense

Abstract: Sour natural gas containing sulfur in the form of hydrogen sulfide (H2S) presents a double cost to producers. First, the gas has to be sweetened with a solvent, and second, most of the H2S has to be converted to sulfur. Both processes are expensive. Acid gas reinjection eliminates sulfur compounds and carbon dioxide (CO2) emissions into the atmosphere. This compression and injection process has been rapidly developed and adopted in Western Canada for handling acid gas streams from sour gas sweetening facilities.

System for removal of hydrogen sulfide from a gas stream

Abstract: A system for removing hydrogen sulfide from a gaseous stream such as one of natural gas. A sour gas stream containing H 2 S is contacted with a nonaqueous, water-insoluble sorbing liquor which comprises an organic solvent for elemental sulfur, dissolved elemental sulfur, an organic base to promote the reactions, and an organic solubilizing agent an agent suitable for maintaining the solubility of polysulfide intermediates which may otherwise separate when they are formed during operation of the process. Hydrogen sulfide (H 2 S) gas is sorbed into this liquor and then reacts with the dissolved sulfur in the presence of the base to form polysulfide molecules. The solution is then sent to a reactor where sufficient residence time is provided to allow the polysulfide forming reactions to reach the desired degree of completion. From the reactor, the solution flows to a regenerator where the solution is oxidized (e.g., by contact with air), forming dissolved elemental sulfur and water. The temperature of the solution is then lowered, forming sulfur crystals, which are easily removed by gravity settling, filtration, centrifuge, or other separation method. Enough sulfur remains dissolved in the solution following removal of the sulfur crystals that when this solution is reheated and returned to the absorber a sufficient amount of sulfur is present to react with the inlet H 2 S gas.

Chemical evolution of liquid redox processes

Abstract: A multitude of processes have been proposed for removal of hydrogen sulfide from gaseous streams. Removal of H 2 S from sour natural gas streams is particularly difficult since low outlet concentrations must be reached before the gas is put into a pipeline. Liquid redox sulfur recovery (LRSR) processes use a solution containing an oxidizing agent that absorbs H 2 S from the gas stream and oxidizes it to sulfur. The chemistry of these processes has undergone considerable evolution in the last 30 years. A number of tradeoffs must be considered in designing LRSR processes. For example, the rate of reaction of the oxidized agent with H 2 S often determines the scrubbing efficiency, but excessive rates of sulfur formation in the scrubber can lead to plugging. Systems based on vanadium and/or anthraquinone disulfonates (ADA) as the redox catalyst had several drawbacks, most of which can be traced to sluggish redox agent kinetics. Current LRSR processes use chelated iron as the catalyst for sulfur recovery. This gives faster scrubbing and re-oxidation kinetics, but chemical degradation of the chelating agent can affect the economics of the process. Plugging of sorption vessels continues to be a problem in some applications. New nonaqueous solvent-based or biological processes may overcome these problems.

FTIR method for VLE measurements of acid‐gas–alkanolamine 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 (VLE) data impedes the commercial application of more efficient alkanolamine systems. The objective of this research was to develop an FTIR apparatus and an in-situ technique capable of making VLE measurements of acid-gas-aqueous alkanolamine systems and to improve the accuracy of vapor-liquid equilibrium measurements at low hydrogen sulfide and carbon dioxide concentrations. The new FTIR apparatus and technique were tested in VLE measurements of low concentrations of carbon dioxide and hydrogen sulfide in aqueous mixtures of diethanolamine.

Experimental Study of Gas Absorption with a Spray Column

Abstract: In order to investigate spray properties, measurements of local fluxes of the sprayed liquid, local number fluxes of drops and local drop size distributions were made for wide ranges of liquid and gas flow rates. An empirical correlation for the volume mean diameter of sprayed drops at the nozzle exit was obtained. Experimental studies of gas absorption with a spray column were carried out for carbon dioxide-air-water and carbon dioxide-air-aqueous sodium hydroxide solution systems over wide ranges of liquid flow rates, feed gas concentrations and initial alkaline concentrations. The observed data for dimensionless rates of absorption of carbon dioxide were compared with the values predicted by a solid sphere penetration model.

Self diagnostic gas sensitive resistors in sour gas applications

Abstract: Gas sensitive resistors with arrays of electrodes have been proposed as self diagnostic devices. Here we confirm in detail the theoretical predictions, using poisoning by hexamethyldisiloxane of the H2S and CH4 responses of SnO2 as examples. We show that poisoning can be unambiguously detected, even in the absence of a target gas, and that the effects may be distinguished from those of variation of gas concentration. A pair of such sensors, one of Cr1.8Ti0.2O3+y and one SnO2 can be used in a 'sour gas' application to distinguish H2S, CH4 and hexamethyldisiloxane while also detecting poisoning. © 1997 Published by Elsevier Science S.A.

High pressure storage and transport of natural gas containing added C2 or C3, or ammonia, hydrogen fluoride or carbon monoxide

Abstract: For storage of natural gas at pressures over 1,000 psia, it is advantageous to add to natural gas an additive which is a C2 or C3 hydrocarbon compound, or a mixture of such hydrocarbon compounds. Above a lower limit (which varies with the additive being added and the pressure), there is a decrease in the amount of power needed to compress the mixture. For storage or pipeline transportation of natural gas at pressures over 800 psia, it is advantageous to add ammonia to the natural gas, in an amount such that the ammonia does not create a liquid phase at the temperature and pressure used. The ammonia-natural gas mixture can be compressed or pumped with a lower energy expenditure than would be needed for an equivalent volume of natural gas alone. When more than 4% by volume of ammonia is present, the pumping through pipelines is also aided by the refrigerant effect of the ammonia, which reduces the temperature of the gas being transported. Instead of ammonia, hydrogen fluoride or carbon monoxide can be added to the natural gas, but these are less preferred than ammonia.

The solubility of mixtures of H2S and CO2 in an mdea solution

Abstract: The solubility of mixtures of hydrogen sulfide and carbon dioxide in a 50 mass per cent aqueous solution of methyldiethanolamine (MDEA) solution has been measured at 40°, 70° and 100°C. Partial pressures of the acid gases ranged from 0.08 to 10 450 kPa.

Method for removing sulfur-containing contaminants, aromatics and hydrocarbons from gas

Abstract: This invention relates to a method for removing sulfur-containing contaminants in the form of mercaptans and H2S from natural gas, which may also contain CO2 and higher aliphatic and aromatic hydrocarbons, and recovering elemental sulfur, wherein in a first absorption step the sulfur-containing contaminants are removed from the gas, to form on the one hand a purified gas stream and on the other hand a sour gas, which sour gas is fed to a second absorption step in which the sour gas is separated into an H2S-enriched and mercaptan-reduced first gas stream, which is fed to a Claus plant, followed by a selective oxidation step of H2S to elemental sulfur in the tail gas, and an H2S-reduced and mercaptan-enriched second gas stream, which second gas stream, if desired after further treatment, is subjected to a selective oxidation of sulfur compounds to elemental sulfur.

Acid/Rock Interactions During Stimulation of Sour Water Injectors in a Sandstone Reservoir

Abstract: A sandstone reservoir in central Saudi Arabia produces sweet, super-light oil. Reservoir pressure support is accomplished by water injection into an aquifer underlying the pay zone. Several water injectors were found to be damaged due to iron sulfide and biomass generated by sulfate reducing bacteria (SRB). The sandstone reservoir is heterogeneous, poorly cemented, and contains up to 11 wt% of clay minerals and up to 0.3 wt% calcite. An experimental study was conducted to design an effective stimulation treatment to restore the injectivity of the damaged wells, while maintaining the integrity of the formation. Various acids including HCI, acetic acid, regular and retarded mud acids were tested. Stimulation additives including H 2 S scavenger (aldehydes), iron control agents(EDTA), corrosion (amines) and scale inhibitors (phosphonic acid) were evaluated. Tests included acid-rock interactions under static and dynamic (core flood) conditions. Spent acid was analyzed for key cations using Inductively Coupled Plasma Spectrophotometry (ICP). Core flood tests indicated that full strength mud acid damaged reservoir cores. Therefore, a half strength regular or retarded HF acid was used. Retarded HF acids which are based on boric acid produced a precipitate (KBF 4 ) and are not recommended for field application. Hydrochloric acid at 7.5 wt% was effective in removing iron sulfide and biomass. However, XRD/XRF analyses indicated that elemental sulfur and CaSO 4 precipitated inside the core, and were present in the core effluent. Addition of EDTA (chelating agent) to the acid substantially increased the concentration of multivalent cations in the core effluent. It also triggered production of fine silica particles and kaolinite, thus the cores were damaged. Hydrogen sulfide scavenger were found not to damage the reservoir cores. Scale inhibitor (phosphonic acid) minimized precipitation of calcium sulfate, however, it caused a significant drop in brine permeability when used at high concentrations ( > 0.3 wt%). Results obtained in this study indicated that a thorough screening of various acids and stimulation additives is needed before stimulating sour wells, otherwise severe damage can occur due to acid reactions with iron sulfide (a corrosion byproduct) and carbonate minerals present in the formation.

Improved cleaning method safely removes pyrophoric iron sulfide

Abstract: Case histories show how refiners have saved time and money by using potassium permanganate to clean equipment such as sour water tanks, hydrocrackers, and cokers.

Effect of Hydrogen Sulfide on Condensation and Flow of Gas Condensate Fluids in Porous Media

Abstract: Condensation and flow experiments were conducted at subsurface conditions in a glass micromodel using reservoir fluids with and without the hydrogen sulfide component. It has been noted that the formation of the condensing phase as well as modes of condensate flow are similar for both fluids. Furthermore, an additional condensate transport mechanism, termed lamella flow, was observed with the sour fluid. It has been concluded that core flow experiments conducted with sweet reservoir fluid should reproduce the flow of sour fluid to a large extent.

Process and system for removal of hydrogen sulfide from a gas stream

Abstract: A process and system for removing hydrogen sulfide from a gaseous stream such as one of natural gas. A sour gas stream containing H2S is contacted with a nonaqueous, water-insoluble sorbing liquor which comprises an organic solvent for elemental sulfur, dissolved elemental sulfur, an organic base to promote the reactions, and an organic solubilizing agent, an agent suitable for maintaining the solubility of polysulfide intermediate which may otherwise separate when they are formed during operation of the process. Hydrogen sulfide (H2S) gas is sorbed into this liquor and then reacts with the dissolved sulfur in the presence of the base to form polysulfide molecules. The solution is then sent to a reactor where sufficient residence time is provided to allow the polysulfide forming reactions to reach the desired degree of completion. From the reactor, the solution flows to a regenerator where the solution is oxidized (e.g., by contact with air), forming dissolved elemental sulfur and water. The temperature of the solution is then lowered, forming sulfur crystals, which are easily removed by gravity settling, filtration, centrifuge, or other separation method. Enough sulfur remains dissolved in the solution following removal of the sulfur crystals that when this solution is reheated and returned to the absorber a sufficient amount of sulfur is present to react with the inlet H2S gas.

Contaminants in a Gas Turbine Fuel System and Thermal Shock

Abstract: Thermal shock has emerged as a probable cause of random cracking in gas turbine hot gas path parts fueled by sweet gas from Eastern Province gas plants in Saudi Arabia. Fuel is distributed to combustion gas turbines in a central Ghawar water injection plant approximately 50 km away through a series of pipelines above grade. To combat the damaging effects of condensates in fuel gas, two stage particle/demister filters were installed on the gas turbines at this plant. Inspections of the filters that protect five WIP drivers, model MS-5002B/AT, have been carried out after 13,000 to 17,000 operating hours. An analytical evaluation of solids recovered from the filters revealed evidence of condensates in the fuel gas including water soluble salts, iron hydroxides and heavy hydrocarbons. There was damage to four out of five particulate filter elements, elemental sulfur found in filter catches, erosion of a stop valve stem, and cracks in the turbine nozzles with no cracks in the buckets’ coating. All of these problems could be attributed to the presence of solid and liquid contaminants in the fuel gas. HYSIM calculations on upstream fuel gas samples support the potential for condensate and gas hydrates, particularly in cooler weather. The results of this study have led to the recommendation to install coalescing filters on gas turbines operating on this sweet gas fuel system. Suspected sources of moisture and heavy hydrocarbons resulting in sudden changes in fuel gas composition and the potential for damage due to thermal shock will be presented.Copyright © 1997 by ASME

A new solution to sour gas wells

Abstract: Major operational problems for the Gas Industry result from the biogenic production of H{sub 2}S in the reservoir. The presence of H{sub 2}S causes corrosion, higher operational costs and reduced revenue, and is a serious environmental and health hazard. The formation of sulfide in the reservoir is caused by the growth and metabolic actions of the sulfate reducing bacteria (SRB). A new technology which removes H{sub 2}S and additionally prevents its biogenic formation by the SRB has been developed. This technology, termed ``Biocompetitive Exclusion,`` is based on the replacement of the detrimental SRB population by the establishment and growth of an indigenous beneficial microbial population which is preferentially stimulated by the addition of a low concentration of a selected water soluble formulation. The system does not require the addition of microbial cultures but is a directed and selective manipulation of the in-situ reservoir microflora and ecology by inorganic nutrients. The effectiveness of this controlled biosystem treatment for decreasing the sulfide concentrations and maintaining low sulfide levels has been demonstrated in oil and gas wells in various field locations and reservoirs as part of a program sponsored by the DOE. This new technology offers the gas industry a low cost andmore » easily applied treatment system to prevent H{sub 2}S in reservoirs and to reduce operational costs.« less

Gas storage method and product

Abstract: For storage of natural gas at pressures over 1,000 psia, it is advantageous to add to natural gas an additive which is a C2 or C3 hydrocarbon compound, or a mixture of such hydrocarbon compounds. Above a lower limit (which varies with the additive being added and the pressure), a decrease in the amount of power is needed to compress the mixture. For storage or pipeline transportation of natural gas at pressures over 800 psia, it is advantageous to add ammonia to the natural gas, in an amount such that the ammonia does not create a liquid phase at the temperature and pressure used. The ammonia-natural gas mixture can be compressed or pumped with a lower energy expenditure than would be needed for an equivalent volume of natural gas alone. When more than 4 % by volume of ammonia is present, the pumping through pipelines is also aided by the refrigerant effect of the ammonia, which reduces the temperature of the gas being transported. Instead of ammonia, hydrogen fluoride or carbon monoxide can be added to the natural gas, but these are less preferred than ammonia.

Method for on-line cleaning of sulfur deposits

Abstract: A method for on-line cleaning of sulfur deposits collected in the absorber column in a Stretford-type process by washing the sulfur deposits with hot caustic solutions while H 2 S is removed from sour gas in the absorber column.

BIODESULF(TM), A Novel Biological Technology for the Removal of H2S From Sour Natural Gas

Abstract: The state-of-the-art technologies for the removal of sulfur compounds from Sour Natural Gas (SNG) are not cost-effective when scaled down to approximately 2-5 MMSCFD. At the same time, the SNG Production is increasing at 3-6 TCF/Yr and -78 TCF potential reserves are also sour. Assuming only 3% treatment of this potential SNG market is for small volume processing, the potential U.S. Market is worth $0.14 to $0.28 billion. Therefore, the Gas Processing Industry is seeking novel, cost-effective, environmentally compatible and operator friendly technologies applicable to the small volume producers in the range of less than 1 MMSCFD to - 5 MMSCFD. A novel biological process, BIODESTJLFTM (patent pending), developed at ARCTECH removes H{sub 2}S and other sulfur contaminants that make the Natural Gas Sour. The removal is accomplished by utilizing an adapted mixed microbial culture (consortium). A variety of anaerobic microbial consortia from ARCTECH`s Microbial Culture Collection were grown and tested for removal of H{sub 2}S. One of these consortia, termed SS-11 was found to be particularly effective. Utilizing the SS-11 consortium, a process has been developed on a laboratory-scale to remove sulfur species from Sour Natural Gas at well head production pressures and temperatures. The process has been independentlymore » evaluated and found to be promising in effectively removing H{sub 2}S and other sulfur species cost effectively.« less