Acid Gases And Their Contribution to Miscibility

The design of an acid gas injection scheme requires a significant amount of information regarding phase equilibria. The purpose of this paper is to review the literature for the available experimental data, and survey methods for calculations of the non-aqueous equilibria. This study will be limited to the following components: hydrogen sulfide, carbon dioxide, methane, ethane, propane, and, to some extent, water. It is demonstrated that the widely available Peng-Robinson equation of state is adequate for predicting the non-aqueous phase equilibria in these mixtures. However, the design engineer should be cognizant of the capabilities of the model selected to perform the calculations. If uncertain, it is wise to verify the software package, and more importantly the chosen model, by comparing it with experimental data. Available data are compiled as a part of this paper. ACID GAS INJECTION Acid gas injection has become the environmentally friendly way to deal with the unwanted by-product of the sweetening of natural gas. In the future it may become a means of dealing with carbon dioxide from other sources as well. In a basic acid gas injection scheme, the acid gas off the amine regenerator tower is compressed and transported via pipeline to an injection well. From there, it is injected into a suitable formation for disposal. The formation is selected based on geological criteria such as the size of the disposal reservoir, and the containment of the injected acid gas. In an acid gas injection scheme, pressures can range from near atmospheric up to 30 MPa or more; the upper limit is dictated by the selected reservoir. The temperature can range from about 30 °C up to as much as 200 °C; again the upper limit is being the reservoir conditions. The design of the injection scheme requires a thorough knowledge of the phase equilibria encountered in wet acid gas mixtures. This paper reviews the experimental investigations into the relevant systems. This study is limited to the following components: hydrogen sulfide, carbon dioxide, methane, ethane, propane, and water. Even so, an interesting variety of phase equilibria will be presented. The design engineer is advised to be aware of all of the various phenomena encountered in mixtures of these components, as they will have a significant effect on the design. Experimental Investigations In this section, experimental investigations important to acid gas injection will be reviewed. Typically, in acid gas injection schemes, we are not concerned with hydrocarbons heavier than propane. So, for this study, only equilibrium between the acid gas components and methane, ethane, and propane will be considered. Hydrogen Sulfide +Carbon Dioxide The most important non-aqueous system involved in acid gas injection is the binary mixture hydrogen sulfide +carbon dioxide, since acid gas is composed almost exclusively of these components. Two early studies of the phase equilibrium in the system hydrogen sulfide +carbon dioxide were Bierlein and Kay(1) and Sobocinski and Kurata(2).

Hydrogen sulphide is of interest as an economic source of sulphur, fromconsideration of corrosion problems, as a health hazard, and as a geochemicalguide. It forms an essential link in the cycle of sulphur, it occurs widely innature, and, with carbon dioxide, is a byproduct of the bacterial reduction ofsulphates. The close association with low contents of dissolved sulphate information waters, and with the presence of sulphate-reducing bacteria in someoil-field waters, is consistent with a biogenic origin for these two componentsin the bulk of natural gases. The few exceptions (natural gases with commonlyless than five per cent hydrocarbons, no hydrogen sulphide and consistingpredominantly of carbon dioxide) probably owe their origin to metamorphism ofbituminous carbonates. The contents of both hydrogen sulphide and carbon dioxide in natural gasesfrom Western Canada vary regionally, although the trend patterns are not alwayssimilar. In some stratigraphic units hydrogen sulphide probably has beenremoved from the aqueous system through reaction with iron in solution and thesubsequent precipitation of pyrite. In other units, oxidation of crude oils mayhave relatively increased the content of carbon dioxide in the natural gases.In spite of the probable operation of these phenomena, the major factorcontrolling the content of hydrogen sulphide and carbon dioxide in naturalgases is the environment of deposition of the sediments, a view that is inaccord with a biogenic origin for both acid gases. Introduction This paper is the second of a series concerned with the geochemistry ofnatural gas in Western Canada. It discusses the acid gases hydrogen sulphideand carbon dioxide. The first paper dealt with the hydrocarbons and the thirdpart will treat the inert gases.

Chapter 7 - Acid gas treating

During development of high sulfur-content natural gas fields, gaseous sulfur is likely to precipitate and deposit in the reservoir and transmission pipelines owing to changes in the temperature, pressure, and gas components. It is important to accurately predict the elemental sulfur solubility in hydrogen sulfide, carbon dioxide, and methane because these are the three main components of high-sulfur-content natural gas. The binary interaction coefficients between sulfur and hydrogen sulfide, carbon dioxide, and methane are the key parameters for predicting the sulfur solubility with a thermodynamic model. In this work, we show that the binary interaction coefficients are not constant, but temperature dependent. Three-parameter temperature-dependent equations for the binary interaction coefficients between sulfur and solvents are proposed. The corresponding regression equations for calculating the binary interaction coefficients between sulfur and hydrogen sulfide, carbon dioxide, and methane are obtained using experimental sulfur solubility data. The average relative errors of the sulfur solubility predicted using the experimental data in hydrogen sulfide, carbon dioxide, and methane using the thermodynamic model with the improved binary interaction coefficients are 6.30%, 1.69%, and 4.34%, and the average absolute relative errors are 7.90%, 13.12%, and 14.98%, respectively. Comparing the improved binary interaction coefficients with four other sets of reported values shows that the solubility values predicted by the thermodynamic model with improved binary interaction coefficients fit the experimental data better.

This chapter investigates three ionic liquids (ILs), namely butyl pyridinium acetate ([BPy][AC]), butyl pyridinium benzoate ([BPy][BZ]), and butyl pyridinium propionate ([BPy][PR]), applied as potential absorbents for acid gases (hydrogen sulfide and carbon dioxide) in natural gas. The molecular dynamics (MD) simulation results indicate that the ILs have a relatively low dynamic and compact structure, with high viscosity in their pure state. Consistent with the findings of other researchers, the qualitative analysis of the simulation data for the mixture of an IL with acid and methane gases suggests that the dynamics of the IL enhances in the presence of these gases. The radial distribution functions reveal strong interactions and structural compatibility between the ILs and hydrogen sulfide molecules, indicating their suitability for hydrogen sulfide absorption. The amount of carbon dioxide gas absorbed by these ILs was calculated to be in the range of 0.08–0.11, while the absorption of hydrogen sulfide gas ranged from 0.12 to 0.18. [BPy][PR] IL exhibited the highest percentage of absorption for carbon dioxide (0.1083) and hydrogen sulfide (0.177). Furthermore, a comparison of the interactions between acidic gases and [BPy][PR] with the results of methyldiethanolamine (MDEA) clearly demonstrates the superior physical absorption of these gases by [BPy][PR].

The purpose of this paper is to review the literature for the available experimental data and briefly survey methods for calculations of the aqueous equilibria of acid gas mixtures; notably, the water content of the gas and liquified acid gas. In addition to water, this study will include the following components: hydrogen sulfide, carbon dioxide, methane, ethane, and propane. The design engineer should be fully informed of the capabilities of the model selected to perform the calculations. If uncertain, it is wise to verify the chosen model by comparing it with experimental data. However, as will be demonstrated, the design engineer should be critical when interpreting the available data. Acid Gas Injection As was stated in the first part of this paper, acid gas injection has become an important method for dealing with unwanted acid gas. A common approach in the design of an acid gas injection scheme is to take advantage of the thermodynamics of these systems. The water content of acid gas mixture has a minimum as a function of the pressure. The design of an acid gas injection project should attempt to take advantage of this minimum, in order to eliminate the need for dehydration(1). Water Content An essential aspect of the design of an acid gas injection scheme is the water content of the acid gas mixture. In addition, it is important to know the effect of the state (gas or liquid) of the acid gas on the water content. Table 1 lists experimental investigations into the water content of mixtures containing hydrogen sulfide and/or carbon dioxide. The study of Selleck et al.(2) is considered the benchmark investigation of the system hydrogen sulfide + water. They published tables of smoothed data, which are commonly quoted in the literature. However, these tables are based on relatively few and scattered experimental data points. Carroll and Mather(3) re-evaluated the phase behaviour in this system, presenting a clearer picture of the equilibria and accurately reflecting all of the available experimental data. There have been many investigations of the water content of CO2-rich fluids. In general, there is reasonable agreement amongst the various sets of data in the low and moderate pressure regions. The benchmark investigation of the phase behaviour in the system carbon dioxide + water was that of Wiebe and Gaddy(4–6). Finally, the author of this paper has performed thorough reviews of the literature, and is unaware of any experimental data for the water content for binary mixtures of H2S + CO2 in the public domain. Such data, if available, would be very useful. There have been several experimental investigations into the water content of hydrocarbons. Table 2 lists those of interest in this study. In this paper, we are not strictly interested in the water content of hydrocarbons, but in acid gas mixtures containing hydrocarbons. We require a model that accurately predicts the water content of hydrocarbons in order to have the confidence that it will work for multicomponent mixtures.

In the Steam-Assisted Gravity Drainage (SAGD) thermal recovery process, high pressure and high temperature saturated-steam is injected into a bitumen-bearing oil sands formation. For most operations, the steam temperature ranges from about 200 to 260°C and thus under these conditions, the bitumen, in the presence of high temperature steam condensate, undergoes hydrous pyrolysis, i.e. aquathermolysis, yielding acid gases such as hydrogen sulfide and carbon dioxide. Current SAGD thermal reservoir simulation models in the literature often take into account complex spatial heterogeneity of the geology and oil composition and the physics of heat transfer, multiphase flow, gas solubility effects, and viscosity variations with temperature, however, few have taken the chemistry of SAGD into account. Here, we have added aquathermolysis reactions to thermal reservoir simulation model to understand reactive zones in the SAGD process and how the process generates acid gases via aquathermolysis. Given the requirement to constrain or handle sulfur emissions from thermal recovery processes, it is necessary to understand both the physical and chemical sides of the processes. Here, we have explored the possibility of triggering the Claus process underground for in situ scavenging of hydrogen sulfide during SAGD. The application of the research results is specifically to SAGD although the results could be extended to Cyclic Steam Stimulation as well. The results demonstrate that SAGD is not only a physical process that operates largely under gravity drainage but that it is also a chemically reactive process which generates hydrogen sulfide and carbon dioxide. The results also demonstrate that hydrogen sulfide generation reactions occur where there is sufficient heat, water, and oil and thus, the reactive zones are mainly at the edges of the steam chamber and in the liquid pool that sits above the production well. Injecting very small amount of sulfur dixode along with steam could result in initiation of Claus reaction underground resulting into conversion of hydrogen sulfide into liquid sulfur. The results of this study are significant given regulated emission limits of hydrogen sulfide from SAGD operations in Alberta, Canada, and moreover, the ability to potentially reduce emissions by altering the operating strategy or through in situ hydrogen sulfide scavengers offers an elegant way to meet these regulations.

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.

The effects of mobile water saturations on oil recovery and solvent requirements were studied in miscible displacement tests on sandstone cores. it was found thatoil, if trapped by mobile water, cannot be easily contacted by solvent, and the amount of oil is directly related to measurable relative-permeability characteristics;miscible displacement Performances for secondary and tertiary conditions are equivalent;long-core tests describe the movement of fluid banks that would occur in field floods; andflooding response for solvent developed from multiple contact of crude oil with carbon dioxide or rich gas in long cores is the same as that for liquid solvents with first-contact miscibility. Introduction Miscible flooding is receiving increasing interest as a means of recovering tertiary oil left after waterflooding. Mobile water is a factor in tertiary flooding, and can also be a factor in secondary operations where alternate water and solvent injection is used to improve the low sweep efficiency of miscible flooding with hydrocarbon and acid gases. Several publications have reported a reduction in displacement efficiency when mobile water is present at the displacement front. Stalkup present at the displacement front. Stalkup summarized this information and also reported increased mixing caused by the mobile water. However, more information is needed to implement recovery operations where mobile water conditions can occur. The purpose of this paper is to provide information about the displacement behavior in those portions of a reservoir that may contain a high water saturation and that are contacted by a solvent. Factors examined arethe relationship of oil trapping by water to relative permeability and wettability,the development and growth of fluid banks,a comparison of first-contact and multiple-contact miscible displacement, before and after waterflooding,the effect of flow rate and system length on multiple-contact miscible displacement, andthe displacement of oil by the simultaneous injection of solvent and water. The experiments performed were in laboratory cores and are not scaled to field conditions in some respects. The study provides insight into some of the pertinent mechanisms of the displacement process rather than data that is directly applicable to a field situation. MATERIALS AND PROCEDURE OIL-TRAPPING TESTS Drainage and imbibition water-oil relative-permeability data were obtained on a water-wet Berea sandstone core using the steady-state test procedure. The dimensions of the Lucite-encased Berea core are given in Table 1. Two series of first-contact miscible-displacement test, one series involving the displacement of water and the other involving the displacement of oil, were performed at various levels of oil and water saturation on the same core. Saturations during the relative-permeability tests and miscible - displacement tests were determined using an X-ray absorption technique. The recovery performance was calculated by refractive index analyses of the produced fluids. To provide for these analyses, two bones and two refined oils were prepared for the tests. TABLE 1 - TRAPPING-ENVELOPE MISCIBLE-DISPLACEMENT TESTS, 2.1-IN.-DIAMETER BY 5.1-IN.-LONG BEREA SANDSTONE CORE Residual In-Place Saturation Solvent Liquid Test Flowing percent PV Flow Rate Saturation Number WOR Oil Water (PV/hour) (percent PV) ------ ------- --- ----- --------- ------------- Drainage Tests - 1.0-cp Nal brine displace by 0.95-cp brine D-1 oo 0 100 2.84 0 D-2 2 29 71 1.79 0 D-3 0.1 45 55 0.284 0.5 Imbibition Tests - 1.48-cp oil displaced by 1.42-cp oil containing iodobenzene I-1 0 74 26 2.85 0 I-2 0.2 43 57 2.28 7 I-3 1 34 66 0.78 13 I-4 5 32 68 2.72 17 I-5 1 35 65 1.21 10 SPEJ P. 217

Experimental data have been obtained on the initial hydrate-forming conditions in systems containing, nominally, 72 per cent and 82 per cent methane, with the balance consisting of various mixtures of hydrogen sulphide and carbon dioxide. The study covered a range in pressure from about 100 psia to 2,200 psia and a range in temperature from about 32°F to 76°F. These data, together with previously published data on systems containing methane and carbon dioxide and methane and hydrogen sulphide, were used to prepare working charts to predict initial hydrate-forming conditions in systems containing about 65 per cent or more methane, with the balance consisting of variable amounts of hydrogen sulphide and carbon dioxide. A comparison was made with results calculated using the concept of solid-vapour equilibrium ratios. The calculated pressures at any given temperature were always higher than the experimental pressures at the same temperature. The average error was about 42 per cent for the 72-per-cent methane mixtures and 52 per cent for the 82-per-cent methane mixtures.

This report describes research from September 29, 1990 through September 30, 1996, involving the development a novel Fourier transform infrared (FTIR) spectroscopic apparatus and method for measuring vapor - liquid equilibrium (VLE) systems of carbon dioxide and hydrogen sulfide with aqueous alkanolamine solutions. The original apparatus was developed and modified as it was used to collect VLE data on acid gas systems. Vapor and liquid calibrations were performed for spectral measurements of hydrogen sulfide and carbon dioxide in the vapor and in solution with aqueous diethanolamine (DEA) and methyldiethanolamine (MDEA). VLE measurements were made of systems of hydrogen sulfide and carbon dioxide in 20 wt % DEA at 50{degrees}C and 40{degrees}C. VLE measurements were made of systems of hydrogen sulfide and carbon dioxide in 50 wt% and 23 wt% MDEA at 40{degrees}C and in 23 wt% MDEA at 50{degrees}C. VLE measurements were made of systems of hydrogen sulfide and carbon dioxide in 35 wt% MDEA + 5 wt% DEA and in 35 wt% MDEA + 10 wt% DEA at 40{degrees}C and 50{degrees}C. Measurements were made of residual amounts of carbon dioxide in each VLE system. The new FTIR spectrometer is now a consistently working and performing apparatus.

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.

Acid gas removal is an important process in various branches of the hydrocarbon processing industry, primarily in natural gas processing and refining. Acid gas removal is also an essential part of other processes, such as coal gasification where carbon dioxide, hydrogen sulfide, carbonyl sulfides, mercaptans, and other contaminants need to be removed. Acid gas is defined as gas containing significant amounts of contaminants, such as hydrogen sulfide (H2S), carbon dioxide (CO2), and other acidic gases. Sour gas is gas contaminated with H2S. This term comes from the rotten smell due to sulfur content. Thus, "gas sweetening" refers to H2S removal, because it improves the odor of the gas being processed, while "acid gas removal" refers to the removal of both CO2 and H2S. Acid gases need to be removed in order to comply with sales gas quality regulations. These regulations are in place to minimize environmental impact and ensure gas transport pipeline integrity, avoiding undesired occurrences, such as corrosion caused by H2S and CO2 in the presence of water. Acid gases also need to be removed due to the toxicity of compounds, such as H2S, and the lack of the heating value of CO2. Typically, "pipeline quality" or sales gas is required to be sweetened to contain concentrations of H2S that's no more than 4 parts per million (ppm), and a heating value of no less than 920 to 1150 Btu/SCF, depending on the final consumer requirements.

There were investigated physico-chemical and absorption properties of new sorbent, that was obtained by means of mixing of fine-grained Portland cement -500, 100 g of gaize from Astrakhan Oblast with 100 cm 3 of 10% aquatic solution of table salt and forming of pellets with desired size (from 0.5 to 5 cm diameter). Formed mass after setting and hardening was placed into current water, and cured so far as water had negative reaction on chloride-ion. After drying at 80-85 o C pellets were placed into 40% aquatic solution of diethanol amine (DEA) during 1 hour, then pellets carried over on sieve, therewith removing excess of DEA, and pellets were predrying in free air (fan) at 20-40 o C. Sorbent SV-DA was used for ambient air cleaning from acidic gases and water vapors, such as hydrogen sulfide, sulfur dioxide, carbon dioxide and microorganisms. Obtained results are testified high absorption properties of sorbent, allowing cleaning ambient air from acidic gases to level less than 0.01 MAC.

Summary This paper presents the material selection, construction procedures, safety devices, corrosion control and monitoring, and operational procedures necessary for successful compression, transportation, and injection of a gas stream containing 28% hydrogen sulfide. It also discusses various operational problems encountered during the 3-year project life. Introduction As Amoco's West Texas waterfloods in the San Andres formation matured, it became evident that they would reach their peak production levels and begin to decline in the early 1970's. It also became evident that recovery of original oil in place through primary and secondary means would be in the range of 25 to 45%. The large quantities of oil which would remain unrecovered led to considerations of tertiary recovery methods.Although much laboratory work had been done in studying tertiary recovery processes, it was recognized that only field testing in a reservoir environment could prove the economic viability of the various tertiary methods. Screening of possible recovery techniques led to the selection of the miscible displacement process as having the most promise in these reservoirs. A company-wide search was made in late 1970 for possible tertiary project sites, and several pilot sites were selected to test the various miscible agents.A portion of the Slaughter Estate Unit which had not been waterflooded was selected as a site for a pilot test of the CO2 miscible displacement process. Fig. 1 shows the location of the Slaughter field in relationship to the West Texas - eastern New Mexico area. Fig. 2 shows the location of the Slaughter Estate Unit within Slaughter field. Eight pilot wells were drilled from March through June 1972, and waterflood operations began in Nov. 1972. Peak secondary oil production was seen in mid-1973, and by mid-1976 a steady secondary decline rate was discernible.It soon was determined that at projected injection rates a reliable source of pure CO2 in sufficient quantities and a means of delivering it to the pilot site did not exist. There was, however, a feed gas stream to the Claus sulfur unit at the Slaughter gasoline plant, about 7 miles (11.3 km) from the pilot site, which consisted of approximately 72% carbon dioxide and 28% hydrogen sulfide. Investigations ascertained that there were no commercially available processes for completely separating the hydrogen sulfide and carbon dioxide in the Claus plant feed gas (hereafter referred to as acid gas). Further, laboratory tests showed that the displacement process using acid gas as a solvent was the same as when CO2 was used. Preparations were made, therefore, to compress the acid gas stream and to transport it through a transmission line to the pilot wellsite.Of course, there was never any consideration given at any time to the use of the acid gas stream as a miscible agent during full-scale field flooding. In any case it would have provided only a tiny fraction of the required volumes of CO2. JPT P. 1065^