Sour Gas Mixtures Research Articles

Prediction model of elemental sulfur solubility in sour gas mixtures

Predicting the solubility of elemental sulfur in sour gas mixtures is one of the most important issues in sour gas reservoirs development. Many experiments have shown the relationship between sulfur solubility and sour gas properties at different temperatures and pressures. However, the solubility model that can be used to predict sulfur solubility at different reservoir temperatures and pressures is rare. Nowadays, Roberts's solubility formula, according to fitting two groups of experiment data, is often used in sour gas reservoirs. Thus, building a solubility formula that contains more experimental data and experimental conditions is very critical. In this paper, based on the correlation formulas for the solubility of various solutes in super critical solvents, a new sulfur solubility formula is built by using a large number of experimental data. Through the comparison and analysis for the new solubility formula and Roberts's solubility formula, the calculation results utilizing the new solubility formula are closer to the experimental data. Therefore, the new formula can be used to predict sulfur solubility in sour gas reservoirs at different temperatures and pressures accurately. The new solubility model can calculate the change of sulfur solubility in sour gas well production and help reservoir engineers to develop the plan of sour gas reservoir development.

Accurate prediction of H2S and CO2 containing sour gas hydrates formation conditions considering hydrolytic and hydrogen bonding association effects

An elegant thermodynamic model, considering the hydrogen bonding association effects in fluid phases by using cubic-plus-association equation of state (CPA EOS), electrostatic effects of hydrolytic dissociation of H2S and CO2 acidic gases according to the modified Pitzer–Debye–Hückle (PDH) model and an improved two step gas hydrate formation mechanism using Chen–Guo model is presented for accurate prediction of the pure and mixed sour gas hydrate formation conditions. The proposed CPA/Electrolyte/Chen–Guo model is quite reliable over wide ranges of temperatures, H2S and CO2 concentrations. The overall average absolute deviation between the predicted and measured sour gas hydrate equilibrium dissociation pressures regarding 149 data points comprising pure and multi-component sour gas mixtures, is about 3.32% which is considerably lower than the other thermodynamic models. The proposed model outperforms the other alternatives both in accuracy and generality and can be employed for accurate design of sour natural gas management and flow assurance systems and gas hydrate energy storage processes in oil and gas industries

Viscosity prediction for natural gas processing applications

The Expanded Fluid (EF) viscosity correlation was used to model the viscosity of mixtures commonly encountered in natural gas processing. This correlation provides viscosity values as a function of fluid density and characterizes each pure compound with three fluid-specific parameters: c2, ρso and c3, when using experimental densities (Version 1) and two parameters, c2 and ρso, when using a cubic equation of state (Version 2). In particular, the original EF correlation for hydrocarbons was adapted for non-hydrocarbon components, including: carbon dioxide, hydrogen sulfide, nitrogen, helium, water, methanol, ethylene glycol, diethylene glycol and triethylene glycol. A temperature dependency was introduced for parameter c2 for components with significant hydrogen bonding such as water and methanol. For all other components, a fixed c2 was found to be adequate. Both versions of the correlation were fit to experimental data for the non-hydrocarbon components with overall average absolute relative deviation (AARD) below 6%. The viscosities of several sweet and sour natural gas mixtures were predicted with overall AARDs of 6.3% and 5.1% for Versions 1 and 2, respectively. The viscosities of aqueous solutions both of methanol and of glycols were also modeled. A binary interaction parameter was required to fit the data for all aqueous mixtures in Version 2 but only for mixtures of water and methanol in Version 1. The overall AARDs of the calculated viscosities of the aqueous solutions of methanol and glycols by Versions 1 and 2 were 6% and 8.7%, respectively.

Injection of Acid Gas Mixtures in Sour Oil Reservoirs: Analysis of Near-Wellbore Processes with Coupled Modelling of Well and Reservoir Flow

The reinjection of sour or acid gas mixtures is often required for the exploitation of hydrocarbon reservoirs containing remarkable amounts of acid gases (H2S and CO2) to reduce the environmental impact of field exploitation and provide pressure support for enhanced oil recovery (EOR) purposes. Sour and acid gas injection in geological structures can be modelled with TMGAS, a new Equation of State (EOS) module for the TOUGH2 reservoir simulator. TMGAS can simulate the two-phase behaviour of NaCl-dominated brines in equilibrium with a non-aqueous (NA) phase, made up of inorganic gases such as CO2 and H2S and hydrocarbons (pure as well as pseudo-components), up to the high pressures (~100 MPa) and temperatures (~200°C) found in deep sedimentary basins. This study is focused on the near-wellbore processes driven by the injection of an acid gas mixture in a hypothetical high-pressure, under-saturated sour oil reservoir at a well-sector scale and at conditions for which the injected gas is fully miscible with the oil. Relevant-coupled processes are simulated, including the displacement of oil originally in place, the evaporation of connate brine, the salt concentration and consequent halite precipitation, as well as non-isothermal effects generated by the injection of the acid gas mixture at temperatures lower than initial reservoir temperature. Non-isothermal effects are studied by modelling in a coupled way wellbore and reservoir flow with a modified version of the TOUGH2 reservoir simulator. The described approach is limited to single-phase wellbore flow conditions occurring when injecting sour, acid or greenhouse gas mixtures in high-pressure geological structures.

Exceptional sour gas ratings for ED-resistant elastomers

The FR25/90 fluoroelastomer from James Walker has been rated with a service life of 142 000 years in a sour gas (hydrogen sulfide, H2S) and liquid hydrocarbon mixture, during qualification to Norsok M-710.

Modelling the hydrate formation condition for sour gas and mixtures

In order to improve the predicting ability of hydrate formation condition for sour gas contained systems, the dissolution of gas in water and hydrolytic reaction equilibrium existing in aqueous phase was taken into account and two concepts, i.e., the true compositions and apparent compositions of aqueous phase, were introduced. And then the approach to determine the true compositions including ionic components was given and the modified method to calculate the component fugacity of aqueous phase was developed by introducing Debye–Huckel electrostatic contribution term. The new method coupled with Chen–Guo model was successfully used to predict the thermodynamics property of hydrates for carbon dioxide and hydrogen sulfide pure gases, binary, and ternary sour gas mixtures in pure water systems. The calculation precision is superior to that of original Chen–Guo model and CSMHYD hydrate software.

Experimental and modeling studies on sulfur solubility in sour gas

The solubility data of elemental sulfur in seven (CH 4+H 2S+CO 2) ternary mixtures were measured in a static cell with the experimental temperature-range (303.2–363.2) K and pressure-range (20–45) MPa. The mole fraction of H 2S in sour gas mixture ranges from 0.0495 to 0.2662 and that of CO 2 ranges from 0.0086 to 0.1039. The Peng–Robinson equation of state was used to correlate the solubility of sulfur in natural gas mixtures. The calculated values are in good agreement with experimental data, and the average absolute deviation is only 6.5%.

Prediction of Vapor−Liquid Equilibria with the LCVM Model: Systems Containing Light Gases with Medium and High Molecular Weight Compounds

The LCVM model (Boukouvalas et al., 1994) is applied to the prediction of vapor−liquid equilibria (VLE) for a variety of binary, ternary, and multicomponent mixtures involving gaseous components (CH4, H2S, C2H6, C3H8, and CO2) with medium and high molecular weight hydrocarbons and/or polar compounds. New interaction parameters (CH4/−CH2O−, CH4/−OCCOH, and CH4/gases) are evaluated, and some existing ones (H2S/−CH2−, CH4/ACH, CH4/ACCH2, and C2H6/ACCH2) are reevaluated by using additional data. Very satisfactory results are obtained in all cases, even for asymmetric systems, where the MHV2 model (Dahl et al., 1991) fails. Of special interest are the successful results for the multicomponent systems that involve up to 24 components, including a H2S-rich sour gas mixture. LCVM is, thus, a powerful model for the prediction of VLE for a broad range of binary and multicomponent systems.

Sour natural gas and liquid equation of state

The major gaseous impurities in the subquality natural gas sources are acidic components, such as hydrogen sulfide and carbon dioxide. Considering that H 2S easily dissociates into hydrogen and elemental sulfur, thermodynamic properties and specially phase equilibria of liquid and gaseous systems containing hydrogen, hydrogen sulfide, carbon dioxide, other acidic components, and light hydrocarbons are of much interest to the natural gas and gas condensate production industries. In this paper we report the development of a simple and accurate cubic equation of state for prediction of thermodynamic properties and phase behavior of sour natural gas and liquid mixtures. This cubic equation of state, which is based on statistical mechanical theoretical grounds, is applied to pure fluids as well as mixtures with quite accurate results. All the thermodynamic property relations of sour gaseous and liquid mixtures are derived and reported in this report. Parameters of this equation of state are derived for different components of sour natural gas systems. The resulting equation of state is tested for phase behavior and other thermodynamic properties of simulated and natural sour gas mixtures. It is shown that the proposed equation of state is simple and predicts the properties of interest with ease and accuracy.

Depositional and Diagenetic Controls on Reservoir Quality and Gas Composition in a Mixed Siliciclastic/Carbonate Setting, Thomasville Field, Mississippi: ABSTRACT

The Smackover Formation in central Mississippi is sour gas productive from siliciclastics interbedded with tight carbonates. The sandstones have low reservoir quality (porosity and permeability of 7.0% and 0.35 md, respectively), but wells are capable of producing at high rates and with large volumes because of the extremely large geopressures and locally thick continuous sandstone packages. Production is from a hostile subsurface environment which includes high temperatures (>365{degree}F), high pressures (>0.88 psi/ft), great depths (>20,000 ft), and variable and corrosive sour gas mixtures (CH{sub 4} = 55%, H{sub 2}S = 36%, CO{sub 2} = 9%). Five fields are productive in this trend; Thomasville, the largest field, is used to illustrate the depositional and diagenetic controls on productivity. Deposition occurred as an upward-shoaling sequence of outer ramp to nearshore and sabkha environments. The lower sandstones are bioturbated, low-quality reservoirs interbedded with carbonate mudstones and packstones; the middle interval consists of the thickest and most continuous sandstones that are interpreted to be amalgamated inner-ramp shoal and ridge deposits; the upper interval consists of the common but tight Smackover ooid grainstone shoals that are interbedded with continuous but thin shoal and shoreface sandstone. The middle interval has the best reservoir quality and contains more » 75% of the hydrocarbons. Seismic may be used to map the sandstone packages but not the individual sandstones. In addition to the larger net/gross and more continuous sandstones in the middle zone, two postdepositional controls also govern the reservoir quality. These include small-scale faulting but more importantly diagenetic events which strongly overprint but do not obscure the original depositional control. At least 15 different diagenetic events have occurred in the sour gas fields that have generally decreased reservoir quality. « less

Correlation of solubilities of gases and hydrocarbons in water

The density dependent local composition (DDLC) model for the Heimholtz energy of a fluid mixture is shown to correlate accurately the solubility of inert and acidic gases and of hydrocarbons from C 1 to C 6 in water at pressures to 300 bar. Further, the local composition model correctly reproduces the experimentally observed maximum in the Henry's law constant curve for gas solubilities in water. The quadratic mixing rules on the other hand, predict no maxima. The new model has been applied to flash problems related to wet sour gas mixtures where the model reproduces the experimental data. The model contains up to three temperature independent binary interaction parameters. When the interaction parameter in the DDLC term is zero, this correction vanishes and the model reduces to one with the conventional classical quadratic mixing rules usually applied to hydrocarbon - hydrocarbon mixtures. The DDLC mixing rule can be applied to any equation of state, which can be divided into a repulsive and an attractive contribution. In this work, we have applied it in conjunction with the Redlich-Kwong equation of state with a temperature dependent a-parameter.

SELECTIVE GAS ABSORPTION UNDER PRESSURE

Abstract For selective removal of H2S from much larger quantities of CO2 under pressure, an industrial prototype spray column has been constructed. Sodium hydroxide solution was atomized by a pressure nozzle of special design and entered the scrubber as fine spray to contact the sour gases. Several operating variables were examined in order to indicate optimal operating conditions for maximum selectivity of H2S over CO2. Fine mist and short contact time favor this selective absorption process. An optimum inlet reactant concentration was found dependent upon the H2S content relative to CO2 in the inlet sour gas mixture. A special nozzle/shield configuration to avoid contact of sour gas with highly turbulent liquid during droplet formation significantly improved the selectivity.

Evaluation of Seal Materials for High-Temperature H2S Service

Abstract The drilling of deeper wells in the exploration for oil and gas has imposed new demands on seal materials used in the completion of these wells. Materials used in the past for the completion of shallow sweet wells well not perform satisfactorily in the deep sour hot environment. These materials undergo serious chemical and physical degration under the conditions imposed by these wells. Seal materials have been tested in the laboratory at various temperatures, from 200 to 450 °F, in 35% H °S, 15% CO2 50% CH4 and pressures from 1,000 to 15,000 psi. The materials have been used in actual field conditions with temperatures up to 425 °F and an 8,000-10,000psi differential across the seals. This paper describes the laboratory evaluation of these materials and the field tests used to develop reliable seals for the harsh environment. Introduction The first well in the Thomasville field, near Piney Woods, Mississippi, was completed with a conventional packer having a sliding-seal assembly set deep in the well. After the production test, it was found that the elastomers in the packer, tubing hanger and valve stem packing had failed. Extensive research revealed that no currently available elastomer could withstand the environment of hot, high-pressure, sour gas for any appreciable period of time. Consequently, well configurations were altered to aboid the use of elastomer seals in the well(1). Research and development of polymeric seal materials at Otis Engineering has resulted in a significant development for oil and gas completions. Laboratory tests were designed to simulate as near as possible the condition encountered in a downhole situation. Sour gas mixtures were specified to contain 35%, H2S (hydrogen sulphide), 15% CO2, (carbon dioxide) and 50% CH4, (methane). Sour crude was obtained and kept under pressure for use in elevated~temperature evaluations. The existing materials were pushed as far as possible in temperature (450 °F) and pressure (15,000 psi) to determine if any were suitable for the severe conditions. The commonly used oil seals were found to undergo serious physical and chemical deterioration. The specific objectives of the test program were:to evaluate various elastomers and thermoplastic materials to determine which were the most resistant to hot, sour gas and fluid conditions;to determine if a combination of materials would perform better than anyone material alone; andto field test qualified materials under the most severe conditions available. Laboratory Tests The environment used in the test program consisted of a gas mixture containing 35% hydrogen sulphide, 15% carbon dioxide and 50% methane. The sour crude contained approximately the same composition as the gas, As the test fixture was charged with gas, a liquid phase of fresh water and diesel oil was also introduced, because it was assumed that these are produced in the formation. The lest chamber (Fig. 1) is made of C-75 and Inconel material for H2S testings. This fixture is heated by an oil bath with careful control of the desired temperature. The major portion of the testing was conducted in a static condition.

Vapor-liquid equilibrium in a six-component simulated sour natural gas system at sub-ambient temperatures

Equilibrium phase composition and refractive index measurements were made on a synthetic sour gas mixture at 8 different conditions over a temperature range from 185.95 to 235.90 K at pressure from 2.74 to 8.04 MPa. In addition, the volume percent liquid at five pressures and the upper retrograde dew point were measured at 235.90 K. The refractive index measurements were used together with the phase compositions to calculate the equilibrium phase densities. These were then used with the overall material balance relationships to calculate the phase volumes. In all but one case, the directly observed liquid volumes agreed well with the calculated values. The disagreement in the results observed near the critical point illustrates the limit of applicability of the method.

The prediction of the PVT properties of sour gas mixtures

AbstractRecent developments in the statistical mechanics of fluid mixtures due to Rowlinson and co‐workers have been applied to H2S/n‐alkane mixtures. The results have then been used to estimate the compressibility factor of a real sour gas mixture and the predicted theoretical value is found to be in excellent agreement with experiment.