Enhancements in Modeling Gas Sweetening

In a coal gasification plant, the acid gases, carbon dioxide and hydrogen sulfide, must be removed from the raw gases in order to produce a purified high Btu product. The carbon dioxide is removed in order to eliminate dilution of the product gas. The hydrogen sulfide is removed to protect methanation catalyst and to meet pipeline gas specifications. Removal of other minor compounds such as carbonyl sulfide and naptha-range hydrocarbons may also be required to protect the methanation catalyst. Braun has grouped the processes which are, or have been, ncluded in the DOE-GRI High Btu gas from coal project according to the composition and pressure of the feed to the acid gas removal unit. This report documents comparisons of conventional absorption type acid gas removal units for the five groups formed. The comparisons are limited to the processes for which Braun received replies to an inquiry specification from the various Licensors of acid gas removal processes. The comparisons were based on the removal of acid gases from the gasifier effluent after it had been quenched and after shift conversion. The composition of the gases was established from the sponsors of the various processes in the joint DOE-GRI program for high-Btumore » gas from coal. The results of the five process comparisons can be related to the partial pressure of acid gas in the feed to the acid gas removal unit. When this partial pressure is higher than about 200 psi, it was found that the Selexol process is the most economical. When the partial pressure is lower than about 200 psi, it was found that the hot carbonate processes are the most economical.« less

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188252, “Natural-Gas-Plant Debottlenecking Thanks to Hybrid Solvent,” by Eric Cloarec, Renaud Cadours, and Claire Weiss, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Processing sour natural gas is a challenge. If mercaptans are present in the sour gas, the limited mercaptan-absorption capacity of the well-known alkanolamine solvents can be a problem. A solution is to replace the usual alkanolamine aqueous solvent with a hybrid formulation that allows simultaneous removal of mercaptans and acid gases. A new solvent has been developed by the addition of a physical component into a generic alkanolamine/water solvent. This hybrid solvent can be used without any plant modification. Introduction More than 40% of identified gas reserves contain acid gases. Over the years, solvent technologies have been developed, demonstrated, and improved for hydrogen sulfide (H2S) and carbon dioxide (CO2) removal. Sour-gas processing has recently seen the requirement of more-stringent specifications for total sulfur compounds, particularly mercaptans and carbonyl sulfide. Producing sour-gas fields in an economic way became a challenge. Indeed, the physicochemical properties of mercaptans allow only very limited reaction with amines under operating conditions. Classical aqueous amine technologies generally are not sufficient to reach mercaptan or total-sulfur specifications. Consequently, additional treatment is required to remove these compounds. The first option to treat a gas containing CO2, H2S, and mercaptans consists of a polishing stage for further mercaptan removal (for example, molecular sieves) downstream from the amine treating process. One drawback of this option is that the gas used for adsorbents regeneration needs to be sweetened, which requires a dedicated unit. Another drawback is that the gas- sweetening unit is generally designed to use a physical solvent, which has high affinity for hydrocarbon. The second option is most often used when the recovery of natural-gas liquids is considered. Mercaptans and other sulfur compounds concentrated in the liquid-hydrocarbon cuts are removed through a caustic-soda process or by molecular sieves. With the first option, the succession of treatment stages requires an increase in plant footprint, which brings unavoidable extended lifecycle costs. Meanwhile, the drawbacks of these schemes include the disposal of the disulfide oil with the caustic-soda process or the treatment of the gas used for molecular-sieve regeneration. The last option is the simultaneous removal of mercaptans, carbonyl sulfide, and acid gases in a single unit by use of a mixture of chemical and physical solvents. However, the mercaptan-removal efficiency is correlated with the solvent composition and flow rate. Design criteria can be for H2S and CO2 removal or for mercaptan elimination. Expenditure optimization will drive the selection of the process scheme: either total mercaptan removal within the gas-sweetening unit or partial mercaptan removal with the hybrid solvent followed by a polishing unit.

When sour natural gases are sweetened with a regenerative solvent, the extracted acid gases H2S and CO2 have to be further handled to dispose of the sulfur in the H2S. The sulfur can be recovered by various processes, which are generally quite expensive. For disposal of small rates of sulfur in the form of H2S, compression of the acid gas stream and injection into an underground zone may be a suitable option. This paper discusses the unique properties of acid gases upon compression and cooling, and the problems that arise in the handling of high pressure acid gas mixtures saturated with water. Methods of overcoming the problems are also reviewed. Process and metallurgical choices are discussed and opportunities for research to minimize costs in acid gas compression and injection are presented. Introduction Sour natural gas contains hydrogen sulfide (H2S), which has to be removed to meet specifications for sales gas. Sour natural gas also contains carbon dioxide (CO2). The removal of H2S and CO2, usually called acid gases, from sour natural gas is accomplished by means of a regenerative solvent. There are several amine solvents used for this purpose. Upon regeneration of the solvent, the acid gases are liberated, and are usually sent to a modified Claus plant, where most of the H2S is converted to elemental sulfur. The acid gas stream to the modified Claus plant consists of H2S, CO2, water vapor and minor amounts of hydrocarbon gas. When the concentration of CO2 is considerably greater than the concentration of H2S in the acid gas mixture, the Claus plant has difficulty in achieving a high sulfur recovery. If the total sulfur rate is small, say less than 5 tonnes/day (t/d), it may be more economical to recover the sulfur by some other process. Such other processes, however, have many drawbacks of their own. An alternative to recovering sulfur on a small scale is to compress and inject the acid gases into a suitable underground zone, in a manner similar to the disposal of produced water. This is environmentally desirable as it eliminates the emission of sulfur compounds and CO2 to the atmosphere. This paper discusses the technical considerations for acid gas compression and injection into an underground zone. Properties of H2S and CO2 Upon removal of the acid gases H2S and CO2 from the sour gas, an acid gas mixture is obtained at low pressure that may also contain about 1 % to 3 % hydrocarbon gases, and which is saturated with water vapor. This is the mixture that is compressed through 4 stages of compression, from about 100 kPa (ga) to around 8 to 10 MPa for underground disposal. In this process water condenses, creating the potential for corrosion and hydrate formation. In addition, at such final compressor discharge pressures, the acid gas becomes a liquid or a dense phase when cooled to ambient temperatures. While experimental results of studies of the physical properties of acid gas mixtures without hydrocarbon components have not been published in the technical literature, the properties of pure CO2 and H2S have been examined and reported. Additionally, the properties of each of the acid gases have also been studied in the presence of water at elevated pressures and temperatures. These results can be used as a guide to indicate how the mixed acid gas streams would behave under the conditions of pressure and temperature when compressed to the injection pressure level. A brief review of the properties of the pure acid gases and the CO2-water and H2S-water binaries is therefore appropriate. Vapor/Liquid Properties of Pure Compounds. In their pure state, CO2 and H2S exhibit the normal vapor/liquid behavior with pressure and temperature, as indicated in Figure 1. P. 193

The profitability of exploration and development of sour gas is sensitive to the processing required for marketing to gas pipelines or as liquified natural gas (LNG). Processing plants required vary widely with the composition of the produced gas. Processing will require removal of CO2 and H2S to meet marketing specifications and can range from simple sweetening and dehydration units to facilities including sulfur recovery and tail gas treating. Additionally, the production of LNG requires even more complete acid gas removal prior to the low temperature processing steps. Several new processes for acid gas removal have been developed which improve the profitability of sour gas production by more efficient acid gas removal. Additionally, the coupling of a cryogenic fractionation step with LNG processing results in an efficient integration of acid gas removal and low temperature processing.

Removing mercaptans from sour natural gas has always been considered as a challenge. This is becoming an even more important issue with the global trend towards more stringent specifications for commercial gases. Amines have been extensively used because of their ability to meet the most severe H2S and CO2 specifications and their very high acid gas selectivity over hydrocarbons, but present very limited mercaptans removal performances. They require an additional treatment step to achieve the total sulfur content specification in the exported gas. Hybrid solvents are more efficient in removing mercaptans, but have the disadvantage of poor acid gas selectivity over hydrocarbons, resulting in hydrocarbon losses with the separated acid gases. Total, taking advantage of its extensive know-how and experience in acid gas removal with amine mixtures, has developed the HYSWEET® process, using a new hybrid solvent formulation allowing simultaneous absorption of acid gases and of mercaptans, with limited coabsorption of hydrocarbons. The solvent was selected at the laboratory scale, with a particular attention given to operation related constraints e.g., cost, corrosion, foaming, degradation…etc. The new solvent's acid gas and mercaptans removal performances were then validated on a pilot rig. The performance of the HYSWEET® process has been assessed for several field applications, and compared with the performances of conventional amine processes. This allowed evaluating the potential gain achievable by the implementation of the new hybrid solvent. The study leads to identify the application cases for which the new hybrid solvent will allow an economic and complete mercaptan removal without any additional treatment, and a perspective of reduction of the additional treatments for the other cases. Besides an economical mercaptan removal, the new hybrid solvent allows a significant reduction in the energy consumption. The results of the techno-economic evaluation of the HYSWEET® process have been confirmed during the first successful industrial application at the Lacq sour gas plant in 2008. Half of the gas production is now treated with the hybrid solvent, allowing the plant to achieve high global mercaptans removal. These results are fully documented in the paper, demonstrating that the newly developed process is a good contender for the development of new sour gas fields to achieve the increasingly stringent commercial gas specifications.

Amine solvent Methyldiethanolamine (MDEA) absorption method remains the most effective approach for removing acid gases: Hydrogen Sulfide (H2S) and Carbon Dioxide (CO2) from sour natural gas. Unfortunately, due to the process relying on chemical reactions, operational parameters become crucial for maintaining its effectiveness. Inaccuracies in these parameters and dynamic changes in chemical and process fluids can disrupt the process, leading to off-specification sales gas and ultimately revenue loss. Donggi Matindok Field produces gas from a carbonate reservoir with a high content of CO2 impurities. Despite optimizing parameters from the plant's base design to accommodate dynamic changes caused by various factors during the carbon dioxide absorption process at the Acid Gas Removal Unit (AGRU), Donggi Matindok still experienced off-specification sales gas due to CO2 levels exceeding acceptable limits. To address this issue, the authors have developed "MiniSorb," a custom-built laboratory tool for simulating the actual acid gas absorption process in AGRU. By replicating the real-time absorption process of amine solvent with the actual feed gas in a lab-scale ratio, the authors could analyze the current state of the absorption process and assess the effectiveness of the operating parameters in removing CO2 from the gas. Through iterations and adjustments, the optimal parameters for amine strength and temperature were determined to generate the most effective absorption reaction, subsequently implementing these findings in the actual plant process. As a result of implementing this method, Pertamina EP Cepu achieved a cost saving of USD 236k annually by avoiding off-specification sales gas and reducing fresh amine solvent usage. This publication introduces a cost-effective, low-risk, and real-time tool for analyzing the effectiveness of acid gas absorption in the process. It also highlights its success in eliminating potential losses in gas sales due to CO2 off-specification in Donggi Matindok Field. The authors hope that this invention can be replicated for other gas processing plants facing similar conditions and problems.

Chapter 10 - Natural Gas Sweetening

High acid gas content streams, consisting primarily of carbon dioxide, hydrogen sulphide or a combination of both are commonly generated as by-products of the sweetening process used to bring many produced gases and solution gases to pipeline specifications for sales and transport. Typically, sour gas has been extracted from acid gases through the use of Claus or other types of elemental sulphur reduction processes, the sulphur sold or stockpiled, and the residual carbon dioxide vented to atmosphere. With depressed prices for the commercial sale of sulphur and environmental concerns with the emission of large volumes of greenhouse gases, industry has shown considerable interest in the feasibility of re-injecting acid gas from sweetening processes, either back into the original producing formation, or into selected disposal zones which may consist of aquifers or previously depleted oil or gas zones. A major concern with the reinjection process is the potential for formation damage and reduced injectivity in the vicinity of the acid gas injection/disposal wells. This paper discusses screening criteria for reservoir selection for zones suitable for acid/sour gas re-injection or disposal, and highlights potential areas of concern for reduced injectivity. Such phenomena include acid gas induced formation dissolution, fines migration, precipitation and scale potential, oil or condensate banking and plugging, asphaltene and elemental sulphur deposition, hydrate plugging and multiphase flow associated with acid gas compression. Variations on acid gas injection schemes, such as concurrent contacting with produced water at elevated pressures and subsequent disposal of the sour water, will also be discussed and potential damage concerns highlighted. A variety of screening and laboratory tests and results will be presented which illustrate the various damage mechanisms outlined and provide a specific set of design criteria to evaluate the feasibility of an acid gas injection/disposal operation. Introduction Acid gases [gases which contain carbon dioxide (CO2) and hydrogen sulphide (H2S)] are produced from many formations as either free gas or liberated solution gas from sour oils. These gases must be "sweetened" to selectively remove the acid gas components before the gas can be transported and sold for commercial use. A variety of sweetening processes are used to remove acid gas components (amine extraction being the most common). The sweetening process results in the production of acid gasfree "sales" gas, and a rich waste gas stream consisting of virtually pure CO2 and H2S (commonly referred to as concentrated acid gas). In the past, a variety of techniques have been used to handle acid gas streams, most of them primarily concerned with the reduction of the extremely toxic hydrogen sulphide to an inert/non-toxic reaction product. The most common technique is the Claus reaction process where the H2S gas in the acid gas stream is catalytically converted to elemental sulphur. This process was an economic one in the past, particularly in regimes of good sulphur commodity prices. Many operators deliberately attempted to exploit reservoirs containing high concentrations of H2S with sulphur recovery as the primary motivating factor.

This paper presents the findings of a study into the consequences of H2S slip into sweet gas from an Acid Gas Removal (AGR) unit amine absorder. Whilst the study was initiated to investigate consequences to downstream consumers with respect to sales gas product specification, during this assessment the implications from a plant operational and metallurgical perspective were also investigated and found to be of critical significance and defined the maximum permissible H2S concentration in the sweet gas leaving the amine absorber. The study assessed the maximum H2S concentration permissible in the sweet gas leaving the AGR amine absorber when considering stress corrosion cracking regions for the downstream plant materials of construction to determine maximum allowable H2S content in sales gas from a metallurgical perspective. The paper also investigated a multitude of operational implications regarding higher than design H2S in the plant sweet gas, including high H2S in the plant fuel gas network. The study found that while the normal operating concentration of 3ppm(mol) H2S in the sweet gas is normally respected, the maximum allowable H2S concentration limit must not exceed 15ppm(mol) due to the risk of stress corrosion cracking in the downstream processing facility. This maximum limit from a metallurgical perspective also avoids all of the operational concerns identified. In the event of an AGR amine absorber operational upset (e.g. loss of lean amine feed), after a relatively short duration, the concentration of H2S in the sweet gas leaving the AGR amine absorber rises rapidly beyond the normal operational concentration and will significantly exceed the 15ppm(mol) minimum limit. As such, plant modifications have been implemented to trip the AGR unit whenever process operating conditions exceed the normal operating envelope due to the potential of the sweet gas to go off spec. This paper will be of interest to sour gas plant operators who remove H2S from their raw gas to meet a gas product specification using amine absorption processes. This paper presents findings of as study in to the operational and metallurgical consequences of exceeding H2S specification in Sweet Gas for a sour gas processing facility.

Natural gas, refinery gas, and coal gas contain acid gases such as hydrogen sulfide (H 2 S) and carbon dioxide that must be removed from the gas stream due to the toxicity of H 2 S and to prevent corrosion to piping and production facility caused by the acid gases. In this article, current technologies for the acid gas removal are selected and reviewed. The review includes absorption, adsorption, conversion of H 2 S into elemental sulfur, and membrane reactor for H 2 S decomposition and desulfurization. Recently, hollow fiber membrane contactor has been in the limelight of research in H 2 S absorption from gaseous mixture due to its potential to overcome problems such as foaming and loading. Recent trends on Claus tail gas cleanup technologies are highlighted due to the recent progress in membrane technology. The article also suggests current research on the acid gas removal technology using catalytic membrane reactor. The interest on finding suitable active component and support and studying the membrane structure for enhanced removal of acid gases is likely to be rekindled in the near future.

Process simulation and optimisation for acid gas removal system in natural gas processing

Publication Rights Reserved This paper was to be presented at the 40th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colorado, October 3–6, 1965, and is considered to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract elsewhere after publication in the Journal of Petroleum Technology or Society of Petroleum Engineers Journal is granted on request, providing proper credit is given that publication and the original presentation of the paper. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Bench experiments and laboratory and field pilot plant testing have led to the development of a solvent that is selective in the removal of CO2 and H2S from natural gas at pipeline pressure. The acid gases are physically absorbed in the solvent; no chemical reaction takes place. Comparative data indicate that our solvent, identified as Solvent P, has certain advantages over a leading competitive, commercially available solvent, which we have labeled Solvent A. Based upon our field pilot plant study, Solvent P has the following advantages over Solvent A as an acid gas removal agent:Higher selectivity, resulting in higher gas yield, smaller refrigeration requirement, or a combination of the two.Higher heating value of the treated gas under comparable treating conditions.Less stripping gas required for solvent regeneration when making 1/4 grain H2S/100 SCF pipeline gas.Higher purity of the flash gases, improving their value for other uses. Introduction Until recently, essentially all commercial acid gas removal processes involved the use of either amines or potassium carbonate solutions. These materials chemically react with hydrogen sulfide and carbon dioxide, giving off appreciable quantities of heat. Heat must be supplied to regenerate the solutions. In recent years, selective solvents have been developed by several companies for the removal of acid gases from natural gas and synthesis gas. The selective solvents operate on the principle of pure physical absorption, as one would calculate using vapor-liquid equilibrium ratios (K-values) for the appropriate systems. Whereas there is a heat of absorption and desorption involved, the heat effects are much smaller than with solutions involving chemical reactions, and the selective solvent can be regenerated without reboiling. Solvent extraction is especially useful in cases where the partial pressure of the acid gas is over 150 psia, preferably over 200 psia. The cost advantage of the solvent extraction process arises largely from the saving of heat ordinarily used in the regeneration of amines and hot potassium carbonate solutions, which is substantial when large volumes of acid gas are involved.

As a sort of emerging unconventional energy, shale gas has extensive market outlook by virtue of its enormous reserves, and concerns for shale gas exploitation and processing have been raised nowadays. Raw shale gas must be processed to achieve certain specifications before it can be transmitted in pipelines or utilized by consumers. Sweetening is a gas conditioning process to decrease the concentration of acid gases such as hydrogen sulfide and carbon dioxide which are not preferred in sales gas in consideration of heating value specification and corrosion prevention. However, the after-treatment of acid gases is not discussed in many research of sweetening process. In this paper, a flowsheet of shale gas sweetening process is established using Aspen Plus v8.6. Dissolution of light gases and weak electrolyte, absorption of acid gases and reactions in electrolyte solution are considered simultaneously in process modelling. Diethanolamine (DEA) solution is employed as the solvent to separate acid gases from raw shale gas. The optimal feed stage of rich solvent regeneration and reflux ratio of regenerator are analysed to optimize the sweetening flowsheet. A three-stage Claus process is simulated coupling with shale gas sweetening process to convert hydrogen sulfide in acid gas to element sulphur for pollution reduction. A principle is proposed to determine the operating temperature of each Claus reactor which is a decisive parameter on sulfur recovery efficiency and performance of Claus process. Ultimately, the sulfur recovery efficiency of the three-stage Claus process proposed in this paper is 97.35 %. The effectivity of the principle is confirmed by the results reported in literatures. Energy synthesis is then adopted to integrate sweetening process with Claus process in both mass and energy flow. The coupled process provides with more streams than a single sweetening or Claus process, promoting the reasonability of energy utilization. Streams are extracted and matched for heat exchanger network (HEN) synthesis to reduce the energy consumption and total annual cost of the whole process.

Petroleum and natural gases besides hydrocarbons may contain acidic gases - carbon dioxide (CO2) and hydrogen sulfide (H2S), and organosulfur compounds - carbonyl sulfide (COS), gray-carbon (CS2), mercaptans (RSH), thiophenes and other components which complicate the transport and use of gases. In the presence of carbon dioxide, hydrogen sulfide and mercaptans natural occurrence of metal corrosion. Hydrogen sulphide, mercaptans, carbonyl sulfide - a highly toxic substance. High concentrations of carbon dioxide in the gases is undesirable and sometimes unacceptable, and also because, in this case reduced calorific value gaseous fuel. If we look at this issue with these products, the sulfur compounds can be classified as undesirable substances. The technological process of processing of natural gas necessary to provide natural gas purification from acidic components. The article explores the process of purification of natural gas solutions of alkanolamines. The problem of increasing the flow of steam in the process of regeneration of the rich absorbent. One problem that arises during purification of natural gas is the increased consumption of thermal energy. It is well known that heat energy is purchased and it allocated substantial funds. The task of solving this problem may be the use of energy-saving technology, leading to a reduction in wasteful heat loss. To achieve this goal in the work the advanced technology amine purification of natural gas from the acid components with varying degrees of regeneration solution. Upgraded scheme allows to obtain the finished product that meets all quality standards.

An All-Purpose Porous Cleaner for Acid Gas Removal and Dehydration of Natural Gas