Надежность подземного хранения водорода совместно с метаном в терригенных геологических формациях

A method has been developed for predicting the critical temperatures and critical pressures of binary mixtures of carbon dioxide, hydrogen sulfide, nitrogen, hydrogen, carbon monoxide and oxygen with the normal paraffin hydrocarbons. For carbon-dioxide and hydrogen-sulfide systems, relations are presented that take into account the peculiar behavior of mixtures with closely boiling components, such as carbon dioxide-ethane and hydrogen sulfide-propane mixtures which exhibit minimum critical temperature points. For hydrogen, nitrogen and carbon-monoxide systems, the extreme critical behavior caused by wide differences in pure component properties is established. In addition, those fixed gas-paraffin systems which resemble paraffin-paraffin systems are also accounted for. For a mixture of known composition, the pure component critical temperatures, critical pressures and normal boiling points are all that are required to determine its critical point. Graphical relations are presented relating Tc and Pc of the mixture to the pure component properties. From the treatment of 12 carbon-dioxide and hydrogen-sulfide systems reported in the literature (74 mixtures), the expected error for the critical temperature is approximately 1.5 per cent, and for the critical pressure, approximately 2 per cent. From the treatment of six hydrogen, nitrogen and carbon-monoxide systems reported in the literature (30 mixtures), the expected error for both the critical temperature and critical pressure is approximately 2.5 per cent. The relationships, which have been developed with only normal paraffins as the hydrocarbon components, may be extended to those isoparaffins and olefins which fall within the allowable volatility ranges. Introduction Many of the fixed gases - carbon dioxide, hydrogen sulfide, nitrogen, hydrogen, carbon monoxide and oxygen - occur in natural mixtures with hydrocarbons. Carbon dioxide and hydrogen sulfide are frequent components of the fluids produced from underground petroleum reservoirs. Nitrogen, carbon dioxide and hydrogen sulfide are present in varying quantities in most natural gases and gas-condensate well effluents. Hydrogen mixtures are of considerable interest in many phases of refining processes of petroleum. The determination of the critical temperatures and critical pressures of such mixtures is of value in vapor-liquid equilibrium studies, for the prediction of the characteristics of underground reservoirs, and for reduced-state correlations of PVT, transport and thermodynamic properties. The accurate estimation of the critical point for binary mixtures is an important initial step toward a complete analysis for the establishment of the critical temperatures and pressures of multicomponent mixtures. Methods for predicting the critical temperatures and critical pressures of binary hydrocarbon systems have already been presented in the literature. It is possible to apply these existing methods to fixed gas-paraffin mixtures but due to their unusual critical behavior, values calculated deviate considerably from experimental values. For systems containing trace quantities of the fixed gases, these methods are acceptable; however, for systems containing more than 5 mol per cent of the fixed gases, these utterly fail to produce reasonable critical values. Consequently, in this study a method has been developed for handling such binary mixtures over the entire composition range. CARBON-DIOXIDE AND HYDROGEN-SULFIDE SYSTEMS The critical behavior and the vapor pressure behavior of mixtures of carbon dioxide and hydrogen sulfide with paraffinic hydrocarbons may be quite similar or quite dissimilar to that of paraffin-paraffin mixtures, depending on the volatilities of the components involved. The critical temperature and normal boiling point of carbon dioxide are very close to the corresponding values for ethane, while its critical pressure is considerably higher than that of ethane. SPEJ P. 197^

"The corrosion protection effect of the new S-1 reagent in media with the pH values of 2.0, 4.0, 6.0, as well as carbon dioxide and hydrogen sulfide added separately and combined to the mentioned media, was first tested under laboratory conditions. The protective effect of reagent S-1 was weak in the corrosion medium without hydrogen sulfide and carbon dioxide. However, as the acidity of the medium and the concentration of the reagent increases, the corrosion protection efficiency of the inhibitor also increases. The highest effect is observed at pH = 2.0 and reagent concentration of 30 mg/l. The corrosion protection effect of the reagent reaches 97% under these conditions. In the media with pH = 4.0 and pH = 6.0 without carbon dioxide and hydrogen sulfide, the protective effect of the inhibitor at the optimal concentration of 30 mg/l is 66% and 64%, respectively. In the medium with added carbon dioxide, the protective effect of inhibitor S-1 decreases at pH = 2.0 and, on the contrary, increases at the values of pH = 4.0 and pH = 6.0. Also, as the pressure of carbon dioxide in the medium increases, the protective effect of inhibitor S-1 increases. When hydrogen sulfide is added to the medium, it causes an increase in the corrosion rate and the protection efficiency of inhibitor S-1. However, in the medium without inhibitor, the increase of hydrogen sulfide concentration only up to CH2S = 400 mg/l is accompanied by an increase in the corrosion rate at all values of pH. The addition of 1000 mg/l of hydrogen sulfide to the corrosion medium leads to the decrease in the corrosion rate in the medium without inhibitors and a slight decrease in the protective effect at the concentration of the inhibitor Cinh = 10 mg/l. As the concentration of inhibitor S-1 increases in the medium with the addition of carbon dioxide and hydrogen, its corrosion protection effect also increases. In the range of Cinh = 10–30 mg/l, when PCO2 = 0.5 atm and CH2S = 200 mg/l, the protective effect is estimated at 38–99%, and when CH2S = 1000 mg/l, it is estimated at 17–79%. At PCO2 = 1.0 atm, the value of protective effect is 22–95% and 14–76%, and finally at PCO2 = 2.0 atm, the value of the corrosion protection effect of inhibitor S-1 is estimated at 44–92% and 15–75%, respectively. The coexistence of carbon dioxide and hydrogen sulfide in an aggressive medium leads to an increase in the protective effect of inhibitor S-1 compared to the medium containing only carbon dioxide, and reduces it in comparison to the medium with hydrogen sulfide. An increase in carbon dioxide pressure in the presence of hydrogen sulfide causes a decrease in the protective effect of inhibitor S-1. The protective effect of inhibitor S-1 is lower in the medium with hydrogen sulfide concentration of 1000 mg/l compared to a concentration of 200 mg/l. This case is also observed in the carbon dioxide free medium."

Complex wells with high temperature and the presence of carbon dioxide and hydrogen sulfide acid gas require the use of high-temperature and high-density anti-corrosion cement slurry for cementing operations, and conventional cement slurry does not have the advantages of high density, high-temperature resistance, or corrosion resistance. In order to avoid the severe corrosion of cement slurry by carbon dioxide and hydrogen sulfide at high temperatures, solid phase particles with different particle sizes are combined with polymer materials to form a dense, high-density, high-temperature- and corrosion-resistant cement slurry. In this paper, we consider the use of manganese ore powder weighting agent, composite high-temperature stabilizer, inorganic preservative slag and organic preservative resin to improve the corrosion resistance of cement slurry, design a high-density cement slurry that is resistant to high temperature and carbon dioxide and hydrogen sulfide corrosion, and evaluate the performances of the cement slurry at 180 °C. The results show that the manganese ore powder weighting agent effectively improves the density of the cement slurry. Using composite silica fume with different particle sizes as a high-temperature stabilizer can ensure the rheology of the cement slurry and improve the ability of the cement sample to resist high-temperature damage. The use of slag and resin as preservatives can effectively reduce the corrosion degree in cement slurry. The high-temperature corrosion-resistant cement slurry systems with different densities designed using these materials exhibit good rheological properties, with water loss of less than 50 mL and a thickening time of more than four hours. The compressive strength decreased by less than 5.8% after 28 days at high temperatures. After being corroded by hydrogen sulfide and carbon dioxide (total pressure 30 MPa, 16.7% hydrogen sulfide and 6.7% carbon dioxide) under high temperature (180 °C) for 30 days, the corrosion depth of the cement sample was less than 2 mm, the reduction of compressive strength was low, and the corrosion resistance was strong. These research results can be used for cementing operations of high-temperature oil and gas wells containing hydrogen sulfide and dioxide.

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.

Natural gas of Tazhong-1 gas field contains 7.7% carbon dioxide and 2.31% hydrogen sulfide, and produced water salinity is up to 140000mg/L,the well-bore tube has seriously potential corrosion destructive with natural gas being exploited. Based on the corrosion type partition of down-hole tube for eighteen production wells of Tazhong-1 gas field, P110,P110S and P110SS corrosion behavior were investigated under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide/carbon dioxide, and corrosion inhibitors were chosen to meet need of anticorrosion of Tazhong-1 gas field. The results show that fifteen wells in eighteen production wells belong to hydrogen sulfide corrosion of both hydrogen sulfide and carbon dioxide influence. Other wells are singular carbon dioxide corrosion. The most severe corrosion of three types of down-hole tubes all occurs at 90°C in both corrosion media, and their corrosion resistance order is respectively P110>P110S>P110SS and P110S>P110SS>P110 under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide and carbon dioxide. The selected anti-temperature corrosion inhibitors (YU-1、YU-4) can control the corrosion rate of three types of down-hole tubular goods within 0.076mm/a in simulated formation water media with carbon dioxide (PCO2=0.08～4.64MPa) or hydrogen sulfide and carbon dioxide (PH2S/Pco2=1.3/4.64Mpa) while added amount of the inhibitor is 120～300mg/L or 200mg/L. All of these provide technical support for safe and fast development of Tazhong-1 gas field.

A knowledge of the equilibrium water content of hydrocarbon systems under pressure is important to the national gas industry. The information available on the solubility of water in hydrocarbon, hydrogen sulfide, and carbon dioxide systems is reviewed in this paper and the influence of the more important variables such as temperature, pressure and molecular structure on solubility in liquids and gases is discussed. A suitable chromatographic technique bas been developed for determining low concentrations of water. Tailing of the water peaks bas been eliminated by adding water to the carrier gas stream The method is applicable for both gas or liquid samples and is effective in the presence of hydrogen sulfide. The experimental study of water solubility in methane-hydrogen sulfide systems at a temperature of 16F has shown that the presence o/ hydrogen sulfide causes only a modest increase in water content at pressures up to 1,400 psia. Theoretical considerations and data on pure hydrogen sulfide and carbon dioxide suggest that the effect of both these compounds will be greater at higher pressures and in the liquid phase. Introduction Before transporting or processing natural gases and gas condensates, it is usually necessary to dry them using suitable dehydration equipment. The design and operation of this equipment requires a knowledge of the amount of water present in the fluid at the reservoir and operating conditions. This is influenced by temperature, pressure and composition, particularly when certain nonhydrocarbon components are present. Field experience indicates that hydrogen sulfide and carbon dioxide, for example, alter the usual water solubility relationships appreciably. However, an extensive search of the literature does not reveal any quantitative data on such systems. For sweet natural gases, generalized empirical correlations such as the one proposed by Katz, et al, can be used to predict water solubility with confidence at most temperatures and pressures of interest. However, existing theoretical relationships do not permit a calculation of the deviation from these curves when polar substances like hydrogen sulfide are present in the system. Thus one must resort to an experimental approach to obtain the necessary information. The fact that laboratory experimental methods frequently involve the use of mercury which reacts with hydrogen sulfide in the presence of water, and that hydrogen sulfide interferes with many chemical reactions specific for water has contributed to the difficulty of studying water solubility in systems containing hydrogen sulfide. In this investigation the water content of a limited member of methane-hydrogen sulfide mixtures was determined using a special technique with gas chromatography. REVIEW OF PUBLISHED DATA Experimentally determined water solubility data have been reported for methane, ethane, propane, n-butane, 1-butene, hydrogen sulfide and carbon dioxide. These studies report the effect of pressure, temperature and molecular structure on water solubility in single component gases and liquids. SPEJ P. 293^

The application of energy-efficient and environmentally safe technology of gas hydrate crystallization for purification of natural gas from hydrogen sulfide (HS) and carbon dioxide (CO) is considered. Thermodynamic modeling of the influence of HS and CO concentrations from 1.00 to 20.00 mol. % on gas hydrate dissociation pressures and filling of gas hydrate cavities with the gas mixture CH — CH — CH — n-CH — CO — HS — N in the temperature range of 273.15—283.15 K has been carried out. It is obtained that increasing the concentration of HS leads to a significant decrease in the dissociation pressures of gas hydrates. The filling of small gas hydrate cavities with HS molecules reaches 0.91. Increasing the concentration of CO leads to a slight increase in the dissociation pressures of gas hydrates. It is found that CO is poorly concentrated in the gas hydrate phase of the considered gas mixture. To extract CO it is necessary to apply multiple gas hydrate crystallization or to use natural gas deposits with low concentrations of CH.

Gravimetric methods were initially employed to examine the influence of inhibitor IB-1 on the corrosion rate of steel in formation water with oil, which contained hydrogen sulfide, carbon dioxide, and a combination of both. In order to assess the effectiveness of inhibitor IB-1, laboratory tests were conducted using samples of steel of grade St3. Corrosion experiments were conducted within sealed containers with a volume of 0.5 liters, using samples sized 30201 mm. The effectiveness of the IB-1 inhibitor in formation water with oil, containing hydrogen sulfide, carbon dioxide, and a simultaneous presence of hydrogen sulfide and carbon dioxide, exhibited a variation within the ranges of 88.3% to 98.0%, 72.4% to 92.7%, and 60.22% to 94.83%, respectively. The laboratory investigations allowed for the determination of the optimal concentration of inhibitor IB-1 to inhibit the growth of sulfate-reducing bacteria and protect steel of grade St3 from corrosion induced by hydrogen sulfide, carbon dioxide, and the concurrent presence of hydrogen sulfide and carbon dioxide.

Using the gravimetric method, the inhibitory efficiency of the combined inhibitor with respect to hydrogen sulfide and carbon dioxide corrosion of St3 steel in model-produced water MI was studied. Corrosion tests were carried out in 0.5 l sealed vessels on St3 samples of size 30×20×1. Gossypol resin + MARZA was used as a multifunctional combined inhibitor. Diesel fuel and kerosene were used as solvent. It has been established that the protective effect of using a multifunctional combined inhibitor in formation water with oil containing hydrogen sulphide and carbon dioxide using kerosene as a solvent ranges from 75 to 96 and for diesel as 80 to 100. The combined inhibitor allows to achieve in the MI medium containing hydrogen sulfide and carbon dioxide in the process of daily testing the corrosion rate of steel is about 0.04 g/ m2∙h only in a concentration of not less than 70 mg/l. However, with an increase in the duration of the test by an order of magnitude, a similar corrosion rate is observed already at an inhibitor concentration of 50 mg/l. The same is characteristic of carbon dioxide and hydrogen sulfide - carbon dioxide solutions. The bactericidal properties of the combined inhibitor with respect to two types of Desulfovibriodesulfuricans and Desulfomicrobium sulfate-reducing bacteria were studied. The effect of the inhibitor on the number of bacterial cells and the formation of hydrogen sulfide in Postgate nutrient medium “B” was evaluated. It has been shown that the combined inhibitor exhibits a bacteriostatic effect on to sulphate-reducing bacteria. It was revealed that the degree of suppression of the number of microorganisms Desulfovibriodesulfuricans at a concentration of the combined inhibitor 100.0 mg/l is higher than Desulfomicrobium. In the latter case, to achieve this effect, 120.0 mg/l concentration of the combined inhibitor is required. The studied combination inhibitor causes inhibition of hydrogen diffusion in steel St3 in the MI medium saturated with H2S and CO2 separately and together, and contributes to preserving the ductile properties of the steel St3 after exposure to solutions compared to non-inhibited media.

Laboratory slim-tube displacement tests have provide new insight into the relative effectiveness of sour gas components in achieving miscibility with reservoir crude. Test results using subsurface fluid samples from the Comet "T" Pool of northwestern Alberta indicate that, as a miscible agent, hydrogen sulphide is slightly more effective than ethane. Carbon dioxide, however, had to be injected undiluted to obtain miscibility. Benham's correlation for predicting miscibility has been evaluated and found to be quite adequate for "sweet" gases, although conservative by at least 4 mol per cent in the required C2-C4 composition. For sour-gas systems, we find that individual components contribute to miscibility in proportion to the relative magnitude of their equilibrium constants. Pseudocritical temperatures are also indicative of miscibility, as suggested by Rutherford, and the possibility of extending this guideline to apply to sour-gas systems is indicated. Introduction IN RECENT YEARS, a fairly large number of reservoirs have been found in western Canada where the acid gases - hydrogen sulphide and carbon dioxide - are major components in the solution gas produced. Although there are attractive prospects for miscibly flooding some of these reservoirs, there is still little understanding of just how the presence of acid gas components influences solvent-crude miscibility. The displacement of oil from a reservoir is miscible when there is no phase boundary or interface between displaced and displacing fluids. Displacement of oil by water is immiscible; displacement of oil by gasoline is miscible. Under certain conditions, fluids such as propane, mixtures of methane with propane or similar combinations of hydrocarbons will give a miscible - and therefore highly efficient - displacement of oil. A. L. Benham(1) devised a relatively simple method for calculating the approximate conditions for a miscibility. This information should provide a better These gases included hydrocarbon components from methane through butane, but excluded hydrogen sulphide and carbon dioxide. Through a series of displacement tests. W. M. Rutherford(2) found that miscibility between reservoir oil and displacing gas is a function of the pseudocritical temperature of the injected fluid. Again, this relationship applied only to light-paraffin hydrocarbons; the miscibility behaviour of other natural-gas components such as carbon dioxide and hydrogen sulphide was not investigated. The main objective of the present work was to evaluate the effectiveness (in comparison with ethane, propane, etc.) of H2S and CO2 in contributing to miscibility. This information should provide a better basis for designing miscible displacement projects where acid gases occur as constituents of the available source injection fluids. With a sour injection gas it should be known, for example, whether a sweetening operation is justified or whether hydrogen sulphide should be left as a component of the solvent bank. In evaluating the economics of such alternatives it is necessary to know whether the add gas contributes tomiscibility in the same way as an equivalent concentration of butane, for example, or serves rather as a noncontributing diluents. Experimental Procedure In all, fourteen displacement tests were run using a 10-foot by 0.25-inch-I.D. "slim-tube", packed with fine (200-mesh) glass beads.

Using the gravimetric method, the inhibitory efficiency of the combined inhibitor with respect to hydrogen sulfide and carbon dioxide corrosion of St3 steel in model produced water MI was studied. Corrosion tests were carried out in 0,5 liter sealed vessels on St3 samples of size 30х20х1. Gossypol resin + MARZA was used as a multifunctional combined inhibitor. Diesel fuel and kerosene were used as solvent. It has been established that the protective effect of using a multi-functional combined inhibitor in formation water with oil containing hydrogen sulfide and carbon dioxide using kerosene as a solvent ranges from 75 to 96 and for diesel as 80 to 100. The combined inhibitor allows to achieve in the MI medium containing hydrogen sulfide and carbon dioxide in the process of daily testing the corrosion rate of steel is about 0,04 g/m2·h. only in a concentration of not less than 70 mg/l. However, with an increase in the duration of the test by an order of magnitude, a similar corrosion rate is observed already at an inhibitor concentration of 50 mg/l. The same is characteristic of carbon dioxide and hydrogen sulfide - carbon dioxide solutions.

Stripping CO2 and H2S from injection water by cycling sweetened hydrocarbon gas countercurrent to the water flow in a contact tower solved a serious corrosion problem in the Wickett waterflood. Introduction Equipment that must handle water containing relatively large quantities of carbon dioxide and hydrogen sulfide is susceptible to corrosion so excessive that it may not be economically controllable using corrosion inhibitors. One such extreme condition developed in a waterflood where selective injection into multiple zones through common wellbores necessitated annular injection, which eliminated the feasibility of using down-hole protective coatings. Severe tubing corrosion was observed and continued even after inhibitor treatment had been increased to as much as 72 ppm. This relatively expensive inhibitor program justified removing the corrosive constituents hydrogen sulfide and carbon dioxide. A process developed for this purpose consisted of stripping these gases from the water by cycling sweetened hydrocarbon gas countercurrent to the water flow in a contact tower. This treatment rendered the water quite suitable for use as injection water in bare tubing and casing with the addition of corrosition inhibitor in economical quantities. Summary From the start, in May, 1963, of the Wickett waterflood in Ward County, Tex., sour El Capitan Reef water mixed with sour produced water has been used for flooding at a rate as high as 40,000 B/D. Although the mixed water was severely corrosive, tests indicated that a prudent inhibitor program could successfully control corrosion in this waterflood. Because the water was injected into 76 injection wells with 175 injection streams, it was necessary to use annular injection to attain selectivity. Corrosion inhibition of the injection waters was highly essential because downhole protective coatings could not be used effectively. Experience using corrosion inhibitors at this flood revealed that corrosion control was not satisfactory even after the inhibitor concentration was increased from 12 to 72 ppm over a period of 2 years. A decision was made to strip the hydrogen sulfide and carbon dioxide from the water by cycling sweetened hydrocarbon gas countercurrent to the waterflow in a contact tower. Since April, 1965, this process has been used to effectively control corrosion process has been used to effectively control corrosion in tubing and casing with the addition of economical amounts of corrosion inhibitor. Sweetening water at the Wickett plant costs about 4.0 mils/bbl. In plants flaring hydrogen sulfide in volumes economically attractive for conversion to sulfur or its allied products for sale, the net income from this operation will defray water treating costs to some degree. Recovery of the 2 tons/day of sulfur available from the flare at Wickett could be economically attractive at 1968 prices; however, the waterflood is too nearly depleted. Sulfuric acid manufactured from the flare gas could become more economical than using commercially purchased acid. Corrosion in Wicket Waterflood The Wickett waterflood began in May, 1963, with injection of 39,000 B/D into 62 injection wells with 175 injection streams. JPT P. 163

The major gaseous impurities in the subquality natural gas sources are acidic components, such as hydrogen sulfide and carbon dioxide. Considering that H2S 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 present equation of state, even though it is simple, predicts the properties of interest with ease and accuracy.

Methane hydrate exists in huge amounts in certain locations, in sea sediments and the geological structures below them, at low temperature and high pressure. Production methods are in development to produce the methane to a floating platform. There it can be reformed to produce hydrogen and carbon dioxide, in an endothermic process. Some of the methane can be burned to provide heat energy to develop all needed power on the platform and to support the reforming process. After separation, the hydrogen is the valuable and transportable product. All carbon dioxide produced on the platform can be separated from other gases and then sequestered in the sea as carbon dioxide hydrate. In this way, hydrogen is made available without the release of carbon dioxide to the atmosphere, and the hydrogen could be an enabling step toward a world hydrogen economy.

The conditions for initial hydrate formation in systems containing carbon dioxide, propane and water were obtained over a wide concentration range for the hydrate-water-rich liquid-gas phase region. The locus of the four-phase equilibrium consisting of hydrate, water-rich liquid, gas and propane - carbon dioxide - rich liquid was determined. The maximum temperature at which hydrates would form in the three-component system was found to be 57.7 °F, compared to 50_3 DF for pure carbon dioxide and 42.3 °F for pure propane. An analysis of the data in terms of the solid-vapour K-factor concept indicated that the If-factors reported for propa.ne do not apply in systems containing carbon dioxide. INTRODUCTION A GAS HYDRATE is an inclusion compound in which water and at least one other component are associated through the enclosure of the hydrate-forming molecules in a crystalline lattice-like structure formed by the water molecules. The process of hydrate formation may be represented by: (Equation Available In Full Paper) where a hydrate-forming gas, R, combines with n molecules of water to form the solid crystalline hydrate. The forces stabilizing the structure are physical in nature, and the value of n may theoretically vary from 5.75 to over 17.0, depending on the hydrate-forming molecule and the structure of hydrate formed (1). Many of the organic and inorganic gases form stable hydrates. These include, for example, carbon dioxide, hydrogen sulphide, methane, ethane, propane and nitrogen, all of which are commonly found in naturally occurring gas reservoirs. For this reason, information on the hydrate-forming conditions of these gases and their mixtures is of importance to the natural gas handling and processing industries. Although extensive experimental work has been reported in the literature on hydrate formation for the pure components, far less information is available on mixtures. Some of the systems for which information is available include methane – hydrogen sulphide(2), methane – carbon dioxide(3). methane-nitrogen(4), methane-propane(5) and propane hydrogen sulphide(6). Initial hydrate formation in several natural gas mixtures is reported by Deaton and Frost(7,8). As an extension of the work reported above, it was decided to study initial hydrate formation in a system containing carbon dioxide and propane. Both of these components are commonly found in natural gas; furthermore, the system is of interest from a phase behaviour point of view, because pure carbon dioxide and pure propane form hydrates in different crystal structures. Hydrate Structure And Phase Behaviour The crystal structures in which hydrates are formed have been classified as Structure I and Structure II by Claussen(9) and von Stackelberg(10,11) and the theory pertaining to this is extensively reviewed by van der Waals and Platteeuw12. In this classification, carbon dioxide, a smaller molecule, forms in Structure I and propane, a somewhat larger molecule, forms in Structure II. The ternary system containing water, propane and carbon-dioxide exhibits two four-phase equilibrium consisting in one case of hydrate II (Hir), water-rich liquid (L1), gas (G) and propane – carbon dioxide – rich liquid (L2) and, in the other case, of hydrate I (Hr), water-rich liquid (L1), gas (G) and propane - carbon dioxide - rich liquid (L2).