Determination and removal of acid gases from natural gas produced from gas condensate plant Ashraf Yehia El-Naggar Egyptian Petroleum Research Institute, Nasr City, Cairo, Egypt. Chemistry department, Faculty of Science, Taif University, Kingdom of Saudi Arabia. Abstract: The major role of gas-condensate plant is to process both associated and non associated gas to produce high-quality natural gas and hydrocarbon liquids. Gas plants have field operations and a network of pipelines that feed the raw natural gas and liquids into the plant. Field operations include dehydration, acid gas (CO 2 and H 2 S) removal and compression. Unless the gas is completely free of any liquids, once it enters the plant, the gas and liquids go into inlet receiving, where the initial gas-liquid separation is made. Our aim is monitoring of H 2 S and CO 2 to select and optimize the conditions of sweetening regenerations in order to follow and prevent their gradient in gas plant. Key Words: - Gas-condensate plant, Dehydration, Acid gas, Sweetening regenerations. I. INTRODUCTION After extracting the natural gas from the underground reservoirs, additional processing is conducted in the field to prevent corrosion and other problems in downstream handling and processing equipment [1, 2], thus, the gas as it leaves the reservoir, is normally saturated with water and, of course, it contains all the impurities normally associated with the gas [3]. All plants have field operations and a network of pipelines that feed the raw natural gas and liquids into the plant. Field operation may include dehydration, CO 2 and H 2 S removal, and compression [4]. Gas and liquids that enters the gas plant pass emergency shutdown valves, which isolate the plant from incoming streams and pig receivers, and then fed to an inlet separator that removes liquid water, heavy hydrocarbons, brine, and particulate matter from the incoming natural gas [4]. The gas is separated from liquids either in a two-phase process, in which gas is typically separated from water, or in a three-phase separation operation, in which gas, water, and liquid hydrocarbons are separated [2, 5]. Three-phase separation is necessary when appreciable liquid hydrocarbons are extracted with the gas and water [6]. Condensed water, hydrocarbon liquids and solids are removed [4]. Water and solids are processed for disposal, and the hydrocarbon liquids go on to liquid processing. Because of the corrosiveness of H 2 S and CO 2 in the presence of water, the toxicity of H 2 S and the lack of heating value of CO 2, sales gas is required to be sweetened to contain no more than a quarter grain H 2 S per 100 standard cubic feet (4 parts per million) and to have a heating value of no less than 920 to 980 Btu/scf, depending on the contract [7, 8]. A. Sampling II. EXPERIMENTAL 1. For gas samples (a) Sample Container Stainless steel sample containers were used. These containers are of a type that ensures maximum safety and are resistant to corrosion by the product being sampled [9]. The sample container is fitted with an internal outage tube to permit release of 20% of the container capacity. The end of the container is fitted with outage tube. (b) Sample Transfer Line - made of flexible metal hose, impervious to the product being sampled, was used. The most satisfactory line is one equipped with two valves on the sample container end. 2. For Liquid samples "condensate samples" A liquid sample was transferred under pressure from a sample point to a floating piston cylinder [10]. The floating piston cylinder (FPC) is designed to collect liquid samples with no vaporization by displacing a piston against a pressurizing fluid (usually an inert gas). The piston serves as a physical barrier between the sample and the pressurizing fluid, at the sampling pressure. The position of the piston at the end of sampling indicates the percent fill of the sample cylinder. 663
B Procedure 1. For gases First, we prepared the connection for the sample cylinder and then opened the main valve of the process line. We opened the second sampling valve and allowed gently flushing (no hydrocarbon condensation should be visible) for 2 minutes (no icing of the valves or sampling lines should occur). The sample cylinder was connected, and both needle valves were opened and flushing was allowed again for 1 minute. We closed the outlet valve of the cylinder and waited 1 minute and closed the inlet valve. We opened the outlet valve and release the sample. Repeat the flushing step and disconnect the cylinder and store in the box for transportation. 2. For condensates First, we prepared the connection for the sample cylinder and then opened the main valve of the process line. We opened the second sampling valve and flushed one liter of sample in an empty mineral water bottle. The sample cylinder was connected, and both needle valves were opened and again one liter of sample was flushed in an empty mineral water bottle. We closed the outlet valve of the cylinder and waited 1 minute and closed the inlet valve. We opened the outlet valve and release the sample. Repeat the flushing step and disconnect the cylinder and store in the box for transportation. C Analysis 1. Gas chromatographic analysis of hydrocarbon gases Hydrocarbons from C 1 to C 9, carbon dioxide CO 2, and nitrogen N 2 were analyzed using Agilent model 6890 plus HP gas chromatograph equipped with thermal conductivity detector "TCD" and flame ionization detector "FID". The packed columns Porapack-Q, 40 ft in length and 1/8 inch in internal diameter or and DB-1 capillary column, 60m in length and 0.320mm in internal diameter were also used in attachment with TCD and FID respectively. Helium gas was used as carrier gas flowing at a rate of 4ml min -1. The elution of the studied gas mixture was achieved with temperature programming form 50ºC to 200ºC at a rate of 10ºC min -1. The quantitative analysis of the gas mixture was achieved using a standard natural gas sample of known composition and according to the standard (159). The injector and detector temperatures were 200ºC and 250ºC, respectively. The data was estimated by integration of the area under the resolved chromatographic profiles, using the HP computer of software chemstation. 2. Analysis of Sulfur Compounds (H 2 S & R-SH) Hydrogen sulfide and mercaptans present in natural gas samples were analyzed using Perkin-Elmer Clarus 500 gas chromatograph equipped with the new and recent Amperometric Sulfur Detector ASD. Tuned DiPMS (Dipoly methyle siloxane) capillary column 60m in length, 0.32 in internal diameter and 4 µm film thickness was used in attachment with Amperometric sulfur detector ASD. Helium gas was used as carrier gas flowing at a rate of 35 psi. The elution of the studied gas mixture was achieved with temperature programming starts form 35ºC and hold for 5 min and then increasing to 150ºC at a rate of 10ºC min -1 and hold for 1min. The reactor temperature is 825ºC. III. RESULTS AND DISCUSSIONS As the gas streams exit the outlet separators, the saturated feed gas, passes from the filter and enters the bottom of the absorber and passes through a Benfield solution, which is used in more than 600 plants worldwide. The Benfield process is a chemical absorption of the H 2 S, CO 2 and to some extent COS. The Benfield process is based on an aqueous solution of potassium carbonate and bicarbonate, with potassium vanadate as an anodic inhibitor and with an amine as an accelerant [11]. The potassium carbonate solution enters the absorber at the top. As the solution flows down the column contacting the up-flowing acid gases (CO 2 & H 2 S), the absorption reactions proceed, and the liberated heat of absorption increases the temperature of the solution. When the upward flowing raw natural gas containing CO 2 and H 2 S contacts the down flowing potassium carbonate solution in a counter current flow. The potassium carbonate absorbs CO 2 and H 2 S and these reactions can be represented as follow [12]: K 2 CO 3 + H 2 O + CO 2 2KHCO 3 K 2 CO 3 + H 2 S KSH + KHCO 3 664
1. Gas streams from outlet Benfield absorption process A. Compositional analysis Table (1) gives the compositional analysis of the gas samples from outlet absorber Tr-1 and Tr-2. The compositions of the gas samples from outlet absorbers Tr-1 and Tr-2 are nearly the same. These gas samples contain up to 3 mol % of carbon dioxide which agree with the pipeline specification limits. Compared to the percent of carbon dioxide in the gas from outlet separators, it is clear that the Benfield solution removes up to 60 % of the original CO 2. The molecular weight of the gas samples from outlet absorbers are lower than that of inlet absorber indicating that beside the absorption of the acid gas components (H 2 S and CO 2 ) the Benfield solution absorbs to some extent high molecular weight hydrocarbons from the feed gas. Accordingly, both the molecular weights and specific gravities decreased. On the other hand, the lower molecular weight hydrocarbons concentrations increased. Also, an advantage of the Benfield solution is that there is minimum co-absorption of hydrocarbons resulting in slight change in the paraffinic composition [13]. Other reason of the slight paraffinic change comes from the distribution of the absorbed amount of CO 2 on all paraffinic compositions in order to keep the total weight percent of the gas sample. B. Sulfur analysis and physical properties The results of sulfur analysis of gas samples from outlet absorbers in the two trains Tr-1 and Tr-2 are given in Table (2). From these results, it was found that the Benfield solution successfully pick up almost all the hydrogen sulfide from the feed gas in all three trips. In addition, the Benfield absorption process removed up to 73% and 66 % of methyl mercaptan from the inlet gases of Tr-1 and Tr-2 respectively for the first trip samples. Also it removed up to 75 % in the second trip samples and 70 % and 72 % for Tr-1 and Tr-2 respectively for the third trip samples. 2. Rich and lean Benfield Samples The compositional analysis of the dissolved gases in both rich and lean carbonate solutions are given in Table (3). The results show that there are some variations in the compositions of dissolved gases from the two separators, which may be due to the absorption efficiency. The dissolved gases are characterized by the presence of high concentrations of carbon dioxide 71.427 to 70.218 mol % for separators Tr-1 and Tr-2 respectively. From the results of CO 2 concentrations, it may be shown that higher absorbing efficiency was observed in Tr-1. With respect to the dissolved gases in the lean carbonate solutions, as observed in gases dissolved in rich samples, there are some variations in the composition; high absorption efficiency observed in separator Tr-1. It was found that the gases dissolved in lean samples from Tr-1 and Tr-2 contains high percentages of CO 2 compared with that of rich Benfield solutions. Table 1: The compositional analysis of gas samples from outlet Benfield absorbers Tr-1 and Tr-2 Separators Tr-1 Tr-2 Percentages Mol % Wt % Mol % Wt % Components Nitrogen 1.053 1.389 1.044 1.385 Methane 78.847 59.581 78.963 59.979 Carbon Dioxide 3.254 6.746 3.143 6.55 Ethane 8.862 12.554 8.972 12.776 Propane 4.63 9.618 4.745 9.91 i-butane 0.916 2.508 0.907 2.496 n-butane 1.507 4.126 1.413 3.889 i-pentane 0.315 1.071 0.292 0.998 n-pentane 0.274 0.931 0.244 0.834 Hexane + 0.342 1.260 0.277 1.183 Total 100.000 100.000 100.000 100.000 665
Table 2: Hydrogen sulphid, Mercaptan and physical properties of gas samples from outlet absorber Tr-1 and Tr-2 Analytical Parameters Tr-1 Tr-2 Mol Wt 21.228 21.118 Specific gravity 0.7329 0.7291 H 2 S, ppm Nil Nil Mercaptan, ppm 6.7 2.4 3. Vent gases from Benfield Regenerators In the regenerator, CO 2 is driven out of the carbonate solution because of its lower partial pressure in the acid gas relative to the corresponding equilibrium pressure of the carbonate solution [11]. Table 3: CO 2 and compositional analysis of gases dissolved in rich and lean Benfield samples of Tr-1 and T-2 Separators Samples Tr-2 Tr-1 Rich Benfield Samples Tr-2 Tr-1 Lean Benfield Samples Components Mol % Mol % Mol % Mol % Nitrogen 0.662 0.673 0.68 0.613 Methane 11.082 12.161 4.866 5.077 Carbon Dioxide 71.427 70.218 78.681 78.123 Ethane 9.506 9.763 7.246 7.404 Propane 1.978 1.822 4.007 4.119 i-butane 1.075 1.053 0.712 0.732 n-butane 1.162 1.101 1.251 1.21 i-pentane 0.642 0.718 0.548 0.51 n-pentane 0.645 0.717 0.545 0.551 Hexane + 1.821 1.774 1.464 1.661 Totals 100.000 100.000 100.000 100.000 The regenerator column runs at near atmospheric pressure and is heated to 112ºC using hot oil. The sudden reduction in pressure experienced in the regenerator flashes a large amount of the acid gases on the regenerator's tray. The steam from the reboiler passes up the packed column and strips the CO 2 and H 2 S from the solution. The steam provides heat to break the chemical bond between the carbonate and CO 2 and accordingly, KHCO 3 is converted back to K 2 CO 3. The compositional analysis of Vent gases from Benfield regenerators is given in Table (4). It was found that the gas samples are composed mainly of carbon dioxide ranging from 96.42 mol % and 94.98 mol % for separators Tr-1 and Tr-2 respectively, in addition to some middle hydrocarbon fractions. The results of the molecular weights of the gas samples indicate that they are characterized by their high molecular weights. These gases being vented to the atmosphere, some safety considerations should be taken into considerations. The results of sulfur analysis are given in Table (4). Of course, the hydrogen sulfide and methyl mercaptan exhibit high values due to the main aim of the Benfield solution which is the absorption of the sulfur compounds. The concentration of the H 2 S and CH 3 SH in the vented gas sample from the Benfield regenerator Tr-1 is higher than that of Tr-2 due to their higher values in the gas from outlet separator Tr-1 than that from outlet separator Tr-2. The concentration of methyl marcaptan shows the same behavior. Table 4: CO 2 and compositional analysis of vent gas samples from Benfield Regenerators Tr-1 and T-2 Separators Tr-2 Tr-1 Components Mol % Wt % Mol % Wt % Nitrogen 0.00 0.00 0.00 0.00 Methane 1.25 0.45 1.62 0.58 666
Carbon Dioxide 96.42 95.22 94.98 93.01 Ethane 0.10 0.07 0.12 0.08 Propane 0.03 0.03 0.06 0.06 i-butane 0.01 0.01 0.01 0.01 n-butane 0.01 0.01 0.02 0.02 i-pentane 0.01 0.01 0.01 0.01 n-pentane 0.01 0.01 0.01 0.01 Hexane + 2.16 4.19 3.13 6.08 Totals 100.000 100.000 100.000 100.000 H2S, ppm 158.6 80.2 Mercaptan, ppm 4.20 1.05 Mol Wt 44.569 44.941 Specific gravity 1.5388 1.5517 IV. CONCLUSION The performance of acid gas removals unite has been monitored by evaluating the amounts of hydrogen sulfide, methyl mercaptan and carbon dioxide. The gas streams at the outlet Benfield absorbers are free from hydrogen sulfide contents and contain much lower contents of methyl mercaptans reflecting the high efficiency of the Benfield absorbers to remove acid gas. The gas vented from Benfield regenerators are composed mainly of carbon dioxide that stripped from the rich carbonate solution. The vented gases contain significant proportions of chloride ions. The high values of hydrogen sulfide present in the gas vented from Benfield regenerators attract our attention to sever health consideration and its recovery should be taken into account. The sulfide contents in rich and lean Benfield samples make the regenerator's tower susceptible to corrosion especially in the presence of water moisture. These high values of sulfides are due to the accumulation of such sulfides in both lean and rich Benfield solutions containers. REFERENCES [1] J. E. Amoore, E. Hautala, Odor as an aid to chemical safety: odor thresholds compared with threshold limit values and volatilities for 214 industrial chemicals in air and water dilution. Journal of Applied Toxicology, Vol. 3, P. 272 290, (1983). [2] EIIP, Preferred and Alternative Methods For Estimating Air Emissions From Oil and Gas Field Production and Processing Operations, Emission Inventory Improvement Program (EIIP), Eastern Research Group, Inc, chapter 10, vol. II., (1999). [3] A. H. Younger, Natural Gas Processing Principles and Technology, part II, university of Calgary, P. 13-1, (2004). [4] A. J. Kidnay and W. R. Parrish, Fundamentals of natural gas processing, Taylor & Francis Group, P. 1:218 (2006). [5] J. E. Rucker, and P. S. Robert, The Petroleum Industry Air Pollution Engineering Manual, AP-40, Air and Waste Management Association. Pittsburgh, Pennsylvania, (1992). [6] GRI, Preliminary Assessment of Air Toxic Emissions in the Natural Gas Industry, Phase I, Topical Report, Gas Research Institute, GRI-94/0268. Chicago, IL, (1994). [7] U. Daiminger, W.Lind, Adsorption Processes for Natural Gas Treatment, Engelhard Corp, U.S.A., P. 14 (2004). [8] TNRCC, Technical Guidance Package for Annual Air Emissions Inventory Questionnaires, Oil and Gas Industry, Draft, Texas Natural Resource Conservation Commission, Austin, Texas, (1996). [9] Annual Book of ASTM Standards, "Standard Test Method for Analysis of Natural Gas by Gas Chromatography", ASTM: D 1945-03, ASTM International, Vol., P. 1-17, 2003. 667
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