In situ gas analysis for high pressure applications using property measurements

A new optical flow cell with a new optical arrangement adapted for high pressures and temperatures using glass fibres to connect light source, cell, and spectrometer has been developed, as part of a larger project comprising new methods for in situ analysis of bio and hydrogen gas mixtures in high pressure and temperature applications. The analysis is based on measurements of optical, thermo-physical, and electromagnetic properties in gas mixtures with newly developed high pressure property sensors, which are mounted in a new apparatus which can generate gas mixtures with up to six components with an uncertainty of composition of as little as 0.1 mol. %. Measurements of several pure components of natural gases and biogases to a pressure of 20 MPa were performed on two isotherms, and with binary mixtures of the same pure gases at pressures to 17.5 MPa. Thereby a new method of analyzing the obtained spectra based on the partial density of methane was investigated.

Hydrocarbon gas often contains some amounts of heavier hydrocarbon and non-hydrocarbon components that contribute to its properties (i.e. viscosity and density). Prediction of the density and viscosity values for hydrocarbon gases is necessary in several hydrocarbon gas engineering calculations such as the calculation of gas reserves, gas metering, gas compression, estimating the pressure gradient in gas wells and for the design of pipeline and surface facilities. Literature correlations for the density and viscosity of pure hydrocarbon gas such as methane, ethane, propane, butane and isobutene are available. However, wide-ranging and accurate correlations for predicting the gas viscosity and density are not available for gas mixtures associated with heavier hydrocarbon components and impurities components such as carbon dioxide, nitrogen, helium and hydrogen sulphide. This paper presents two new models for estimating the density and viscosity of pure hydrocarbon gases and hydrocarbon gas mixtures containing high amounts of pentane, plus small concentrations of non-hydrocarbon components (i.e. carbon dioxide, nitrogen and helium), over a wide range of temperatures and pressures on the basis of fuzzy logic approach. The density model was developed using apparent molecular weight, pseudo-reduced temperature and pseudo-reduced pressure. However, the viscosity model was developed using density, apparent molecular weight and pseudo-reduced temperature. The fuzzy models were derived from 5,350 measurements of density and viscosity of various pure gases and gas mixtures. The partitioning of the input space into the fuzzy regions, represented by the individual rules, was obtained through fuzzy clustering. Accuracy of the new fuzzy models was compared to various literature correlations by blind tests using 1,460 measurements of density and viscosity. The results show that the new fuzzy models are more accurate than the compared correlations. Introduction Accurate determination of the density, viscosity and phase behaviour of pure hydrocarbon gases and hydrocarbon gas mixtures is essential for reliable reservoir characterization and simulation and, hence, for optimum usage and exploitation. The variety of possible natural gas mixtures at different conditions of interest preclude obtaining the relevant data by experimental means alone, thus, requiring the development of prediction methods. Natural gas is a mixture of many components. Wide ranging correlations for the viscosity of the lower alkanes, such as methane, ethane, propane, butane and iso-butane, have already been developed and are available in the literature(1–3). However, wide-ranging correlations are often not readily available for many of the higher alkanes and impurities such as carbon dioxide and hydrogen sulfide. These impurities may be present in small quantities in natural gas and are important when modelling the mixture properties(4). In this paper, the fuzzy logic technique was applied for developing new efficient empirical models to estimate density and viscosity of pure hydrocarbon gases (from methane to pentane) and hydrocarbon gas mixtures (different gas mixtures of methane with ethane and/or propane,...., n-Decane) containing small concentrations of non-hydrocarbon components (i.e. carbon dioxide, nitrogen and helium) over a wide range of temperatures (0–238 °C) and pressures (1–890 bar). The new models are designed to be simpler and more efficient than the existing equations of state (EOS).

This paper presents the second phase of a comprehensive, three-year laboratory study designed to measure gas-water interfacial tension (IFT) at high-pressure/high-temperature (i.e., HP/HT) reservoir conditions. The first phase of our laboratory study (Rushing, et al., 2008a) evaluated the effects of pressure and temperature as well as common nonhydrocarbon contaminants (i.e., CO2 and N2) in the gas phase on gas-water IFT for several dry gas mixtures with specific gas gravities ranging from 0.5781 to 0.7664. These gas mixtures contained primarily methane but also had small percentages of ethane and propane. Carbon dioxide or nitrogen concentrations ranged from 0, 5, 10 and 20 mole% each. All measurements were made with distilled water. The second phase of our study, which is presented in this paper, extends the work of Rushing, et al. (2008a) with the primary objective of evaluating the effects of gas phase hydrocarbon composition on gas-water IFTs at HP/HT reservoir conditions. Gas compositions of the tested gas mixtures from Phase I were expanded to include an additional five hydrocarbon components so that the final tested gas mixtures had components ranging from methane to n-hexanes. The resulting gas mixtures had specific gas gravities from 0.8871 to 1.0101. Similar to the first part of our study, we also evaluated the effects of CO2 and N2 in the gas phase. To establish base lines for comparing the effects of hydrocarbon and non-hydrocarbon composition, we also measured IFTs for the CH4-H2O system at HP/HT conditions. Gas-water IFTs for all gas mixtures were measured at pressures ranging from 1,000 psia to 20,000 psia and at temperatures of 300°F to 400°F. The single-gas-component base line measurements were made at the same pressure range but included two additional temperatures of 122ºF and 212ºF. Note that the gas mixtures for both study phases were designed to be "dry" gases which we define as one that remains in the single hydrocarbon (gas) phase during the entire isothermal pressure depletion path. All gas-water IFTs were measured using a pendant drop method with computer-aided image processing and analysis. Based on the measurements, we observed the following general behavior in gas-water IFTs at HP/HT conditions: Increasing the concentration of intermediate and heavier molecular weight hydrocarbons has a significant impact on the gas-water IFT. The largest difference occurs at lower temperatures and in the higher pressure range. Temperature still has the most significant impact on gas-water IFTs for all gas mixtures and at all pressures. Generally, increasing temperature decreases gas-water IFT. The presence of CO2 in the gas phase had little to no impact on the gas-water IFTs for both 300ºF and 400ºF. In general, CO2 caused IFTs to increase slightly at lower pressures. At higher pressures, the IFTs either decreased slightly or did not change regardless of the CO2 concentration. The presence of N2 in the gas phase had a much more significant impact than CO2 but only at the lower temperatures. For all gas mixtures, gas-water IFTs increased over most of the pressure range evaluated in this study. However, the decrease in IFT caused by increasing temperature completely countered the increase caused by N2 at 400oF.

This paper presents preliminary results from a laboratory study designed to measure gas-water interfacial tension (IFT) at high-pressure/high-temperature (HP/HT) reservoir conditions. We used a pendant drop method with computer-aided image processing and analysis to measure gas-water IFT for several dry gas mixtures at pressures from 1,000 psia to 20,000 psia and temperatures of 300°F and 400°F. For our study, we define a dry gas as one that remains in the single hydrocarbon (gas) phase during the entire isothermal pressure depletion path from the reservoir through surface conditions. We also evaluated the effects of two common nonhydrocarbon contaminants (i.e., carbon dioxide and nitrogen) on the gas-water IFT behavior. Gas mixtures contained up to 20 mol% of either CO2 or N2 each. Finally, we evaluated the effects of total dissolved solids content in the connate water. All IFT measurements were made with either distilled water or synthetic brine with total dissolved solids concentrations of 100,000 ppm NaCl. Study results demonstrate the complex interactions between pressure and temperature as well as gas and water compositions on gas-water IFT. Specifically, we observed the following behavior in the measured IFT: temperature has a significant impact on gas-water IFT. Increasing the temperature from 300°F to 400°F tended to decrease the IFT for all pressures and gas compositions; the effects of CO2 varied depending on pressure, temperature, and concentration. For a given temperature, the presence of CO2 in the gas decreased the IFT at higher pressures; however, the pressure at which this trend was observed varied. Generally, higher concentrations of CO2 resulted in lower IFTs over a much greater pressure range than for the gases with lower CO2 concentrations; the effects of N2 also varied depending on pressure, temperature, and concentration. For lower N2 concentrations, we observed higher IFTs over the entire pressure range than for the gas with no N2. However, the gases with higher N2 concentrations had higher IFTs for the low pressure range only; the presence of total dissolved solids in the water caused the gas-water IFT to be higher than the values measured with distilled water. Higher concentrations of NaCl dissolved in the water caused greater increases in IFT for all pressures, temperatures and gas compositions evaluated in the study.

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 Maureen field, a light oil reservoir in the North Sea which has achieved waterflood oil recovery close to 53 percent of the OOIP is nearing the end of its producing life under waterflooding operations. This field was evaluated as to the feasibility of improved oil recovery through high pressure air injection as an inexpensive substitute for other unavailable or costly gases. Six accelerating rate calorimeter (ARC) tests and five combustion tube tests were conducted to determine the oxidation characteristics of Maureen crude oil while injecting air in the presence of reservoir rock and brine. These tests showed that Maureen oil will reliably autoignite, generate flue gas (85 % N2 and 15 % CO2) and propagate a stable combustion front. In addition with air enrichment, a first contact miscible displacement process can be maintained. High pressure air injection was then modeled as a miscible process using the history matched Maureen waterflood model: the results showed incremental oil recovery due to air injection would range from 17.8 to 26.3 MM STB (4.5 to 6.6% OOIP) depending on the relative location of the air injection wells (flank or crestal). Introduction The Maureen field in the UK sector of the North Sea has achieved water flood oil recovery close to 53 % of the original oil-in-place (OOIP), but is nearing the end of its productive life under water- flooding operations. The water flood has achieved a volumetric sweep efficiency in the range of 90 percent and most of the reservoir hydrocarbon pore volume has been reduced to the residual oil saturation to water of 23 percent, but if abandoned in its present state, Maureen will leave 175 MM STB in place as unrecoverable oil. The next phase of economic oil recovery will require a displacement fluid that is near first-contact miscible, can be recycled, and is available offshore for less than $1.5 US/reservoir bbl. One way to achieve these objectives is through high pressure air injection. High pressure air injection can reduce the residual oil saturation through formation of a miscible gas bank which will displace the remaining oil to the producing wells. This was confirmed by phase behavior modeling of Maureen oil and combustion product gases. Scoping model runs show that high pressure enriched air injection (30 percent oxygen) in a waterflooded reservoir can generate a first-contact miscible fluid in-situ for less than $1.5 US/reservoir bbl. Laboratory combustion tube tests with Maureen oil and core material show that oxygen will oxidize about 3 to 5 saturation units of the oil to create carbon dioxide, generate heat for the steam, and upgrade the oil by 2 to 4 API units. The miscible gas mixture is expected to consist of 34% steam, 16% CO2 and 50% N2. As the extracted oil and steam cool, the foamy oil and water will form a temporary emulsion until carbon dioxide separates from the liquid phases. This temporary emulsion prevents oxygen bypassing the oxidation front and improves sweep efficiency by decreasing the mobility ratio to less than 0.5. Based on Permian Basin experience of enhanced oil recovery from waterflooded reservoirs in west Texas, a carbon dioxide rich gas mixture would be the ideal fluid for increasing oil recovery from the Maureen reservoir. A carbon dioxide gas mixture will recover an additional 8 to 15 percent of the original oil-in-place in the contacted reservoir volume over that achievable by water-flooding. As the reservoir temperature increases due to depth of burial or due to combustion, less carbon dioxide is required in the gas mixture to effectively extract most of the medium to light gravity oil. For temperatures over 200 C, water (in the steam phase) and carbon dioxide can be injected to create a first-contact miscible gas mixture. Experience learned from Amoco's West Hackberry project and Koch's Medicine Pole Hills project shows that it requires about two-thirds of a pore volume of injected air to sweep the reservoir. Laboratory tests show the Maureen oil will autoignite at reservoir temperature, therefore only a single well huff-and-puff test will be required to prove the Maureen oil will oxidize at field conditions. P. 655^

Low permeability reservoir, with small pore radius, narrow throat and low permeability, accounts for a high proportion in the recent years. It is hard to develop by water flooding because of the high injection pressure. And thus gas injection is an attractive process owing to its high injection ability. However, gas channeling and poor flooding efficiency frequently occur during immiscible displacement, and thus the ultimate recovery is not as high as we expected. To find a more effective method to resolve the problems above, we initially inject high temperature mixture gas of flue gas and steam to enhance oil recovery of low permeability reservoir, which combines the advantages of nitrogen gas injection, carbon dioxide injection and steam injection. In this paper, the experiments of different injection fluids, such as water, flue gas flooding, steam and high temperature mixture gas were conducted on low permeability natural cores under reservoir conditions. And the influence factors of mixture gas injection were investigated in detail by numerical simulation method. The results show that, comparing with water flooding and flue gas flooding, the high temperature mixture gas flooding can enhance oil recovery dramatically. It can prevent gas breakthrough early and supplement formation energy quickly. It also can reduce heat loss and increase the heat areas. The steam distillation effect is enhanced during high temperature mixture gas injection, which can reduce residual oil saturation. The more proportion of carbon dioxide in mixture gas and the higher steam dryness are, the higher oil recovery enhanced is. There are different optimal injection rates and ratios of flue gas to steam under different reservoir conditions. The result can be used to gas injection design and has great instruction meaning for the low permeability reservoir development.

Dielectric Barrier Discharges (DBD) have been used for more than a century, especially for ozone production. Research conducted within the last twenty years has investigated the discharge mechanisms involved and the different discharge regimes observable (filamentary, glow, Townsned and multi-peaks). These studies highlight the fundamental role of metastable species to establish and maintain a homogeneous discharge. These recent improvements in understanding the physics of DBD's open perspectives for new applications and new interests in atmospheric pressure surface treatment. Working at atmospheric pressure for silicon oxide deposition is of great interest : the possibility of continuous process, no vacuum component costs and maintenance, no loading/unloading time. However, in comparison with a classical plasma enhanced chemical vapor deposition (PECVD) process, the high pressure and thus the high gas density may result in a gas phase chemistry and a larger formation of dust particles. Exploring a new pressure range from 10 to 1000 mbar could be an alternative for this process. In the first part of this work the effect of the pressure on a DBD in non-reactive gases (helium, argon and nitrogen), then in neutral gas/oxygen mixture has been investigated with electrical measurements (discharge current and applied voltage), with high-speed imaging and with time-resolved optical emission spectroscopy. The second part of this work is dedicated to SiOx barrier coating characterization (FTIR-ATR, XPS, AFM and SEM) as a function of pressure in oxygen/hexamethyldisiloxane (HMDSO) gas mixture highly diluted in nitrogen. The exploration of discharge regimes as a function of pressure shows, in nitrogen, a progressive transition from Townsend to multi-peaks regime between 320 and 160 mbar. A detailed study of this regime in helium and nitrogen with high-speed imaging shows that each multi-peak corresponds to a new spatially homogeneous discharge. However, the discharge is not completely extinguished between each pulse and the remaining light emission reveals the metastable activity (excitation transfer or Penning effect). Paschen's curves obtained from electrical characterization of the discharge show an inversion (compared to standard cuves) of argon and helium cuves. This inversion shows the importance of metastable energies and capabilities to ionize almost all impurities, in the case of helium. This explains why in helium a breakdown under a lower electric field than in argon is possible. A detailed study of a glow discharge in helium as a function of pressure and impurities with time-resolved spectroscopy showed the metastables evolution within a discharge and the role of impurities in quenching or creation rate of metastables. This study also shows a 4 minutes time for thermal stabilization of the discharge (electrode heating and thermosdesorption). In helium and nitrogen, the very first microseconds of discharge are filamentary and change after 2-3 periods (∼ 200 µs) to the glow or Townsend regime respectively. Adding oxygen, an electronegative and metastable quencher gas, make the discharge change to filamentary when a proportion of more than 1500 ppm is added at atmospheric pressure. This rate is increased until 2 % in nitrogen at 350 mbar. The presence of a polymer substrate reduced this Townsend working domain due to the increase of impurities in the discharge caused by polymer etching. However, this process in pure nitrogen is very efficient for implanting nitrogen functional groups on the surface of polymer films. An incorporation of 23 % of nitrogen onto a PET surface has been reached. Regarding SiOx thin film deposition, adding HMDSO, even for ∼ 100 ppm make the discharge change to filamentary. A pressure below 40 mbar must be reached to obtain a multi-peak regime. This high pressure process is fast and deposition rate of 17 nm/s could be obtain at 500 mbar. FTIR, AFM and SEM characterisation of the coatings showed an inhomogeneous composition and structure of the layer between entrance and exit of the discharge along the gas flow. These conditions could explain that the best oxygen barrier obtained was 40.5 cm3/(m2· atm · day). Depending on the discharge parameters (frequency, residence time, power and pressure) the coatings are more or less organic. A progressive decarbonification of the layer due to progressive monomer depletion explains this behavior. A higher oxygen rate allows a better film composition homogeneity along the discharge, while a longer deposition time results in a rougher coating but has no effect on the layer composition. The particular geometry of the discharge cell (6 cm by 6 cm electrodes and 2 mm gap) with gas injection from one side, leads to a different chemistry along the gas flow. At the entrance, the coating is smooth (Ra ∼ 5 nm) and dense but organic whereas at the exit it is rough (Ra ∼ 15 nm) but has a quasi-stoechiometric composition. These differences are explained by heterogeneous reactions, comparable to PECVD process (surface chemistry) close to the gas input and a progressive transition to homogeneous reactions at the exit of the discharge (volume chemistry) which result in particle formation of nanometric size. Analysis of these particles by laser light scattering (LLS) shows a pressure threshold of 200 mbar with a constant gas mixture and flow within all the pressure range. At this pressure, the first detectable particles appear at the end of the discharge. From 200 to 1000 mbar, this threshold becomes closer and closer to the discharge entrance, but it always corresponds to a residence time of the gas in the discharge of around 30 ms. Thus this time corresponds to the characteristic formation time of detectable particles in the discharge. We also showed that this threshold varies linearly with the power injected in the discharge, the higher the power the faster the particles appear. Spatio-temporal LLS measurements show a cyclic (Τ ∼ 1-2 s) formation of particles. This behavior is linked to a rapid growth and a trapping of the particle in the discharge when they reach a 200 nm size. Then, when their size or density increases (∼ 240 nm) they are collected on the electrodes or expelled by the flow drag force which becomes preponderant in comparison with the electrostatic trapping force. Finally, they agglomerate at the exit of the discharge up to ∼ 300 nm size. Then a new cycle starts. This global approach of SiOx deposition process by DBD opens new perspectives of applications in a new pressure range and show the key parameters to be adjusted for an industrial application.

This paper describes two setups devoted to the investigation of the characteristics of the detonation products of gaseous explosive mixtures at high initial pressures. Despite numerous studies performed in the field of the equations of state of dense gases, a lack of knowledge actually remains in the range of pressures from several hundreds of bars up to several kilobars. Such pressures can be obtained in the detonation products of gaseous explosive mixtures ac a high initial pressure. The main difficulty arising when such explosives are used, is the design of appropriate devices that can withstand safely quite high detonation pressures. In order to provide data on the properties of detonation waves of gaseous explosive mixtures at elevated initial pressures, an investigation has been undertaken. The aim of the present paper is to describe two devices that allow the detonation of gaseous mixtures at initial pressures reaching 200 bars. Their common feature is the high pressure technology involved in their design. The experimental study is focused on the measurement of the detonation velocity. In that purpose, ionization probes are used and the mixtures are ignited by means of a powerful energy delivered through a detonator. In such a case, a stable detonation can be expected.

Influence of high pressures on CH4, CO2 and H2S solubility in polyethylene: Experimental and molecular simulation approaches for pure gas and gas mixtures. Modelling of the sorption isotherms

Zinc (Ⅱ) tricarboxylate (Zn-BTC) with metal-organic framework (MOF) has been synthesized for the first time under solvothermal conditions and has been tested as an adsorbent for methane and carbon dioxide at standard temperature and pressure. The adsorbent was characterized by means of X-ray diffraction(XRD), Brunauer-Emmet-Teller (BET), Fourier transform infrared (FT-IR) and scanning electron microscopy (SEM). Sorption capacity of the methane and carbon dioxide on Zn-BTC in the range of pressure 1-20 bar and at 298 K was investigated by volumetric measurement. This results show that Zn-BTC has higher sorption capacity methane at 20 bar compared to carbon dioxide. The high sorption capacity of this adsorbent for methane is attributed to large number of open metal site and the appropriate pore diameter of framework that caused higher interaction for the methane at between methane and carbon dioxide, suggests that (Zn-BTC) is a potential adsorbent for the separation of methane from gas mixtures.

: The acute effect of high ambient pressure on expiratory airflow was studied in healthy, adult males in the ambient pressure range from 1.0 to 7.0 atmospheres absolute pressure (Ata), using a hyperbaric chamber. Changes in flow were assessed with the maximum expiratory flow-volume curve. The decrease in flow was compared to that occurring in dense high molecular weight gas mixtures. In addition, expiratory gas flow was studied in three men during 12 days at 7.0 Ata in 90% helium. The findings demonstrate that: (1) High ambient pressure and high molecular weight gas of equal density produce similar changes in expiratory flow; (2) In the pressure range from 1.0 to 4.0 Ata in air, the greatest decrease in maximum expiratory flow occurs at high lung volumes, while from 4.0 to 7.0 Ata the greatest flow change occurs at low lung volumes; (3) The long-term changes in expiratory flow in high-pressure helium can be explained by the change in physical properties of the breathing mixture; and (4) There are no clinically apparent untoward effects from prolonged high-pressure helium breathing.

An accurate method to predict volumetric behavior of gas mixtures, such as in the case of underground gas storage where the in-situ gas is mixed with the injected gas, is presented in this paper. This method accurately calculates the compressibility (Z) factor of pure hydrocarbon, non-hydrocarbon gases and gas mixtures. These calculations are based on correction functions developed from correlation of data (Z-factor) generated by the Peng-Robinson equation of state. The correction functions are function of gas composition, pressure and temperature, so the Z-factor can be calculated explicitly from gas composition under different reservoir conditions. Several comparative examples are presented to compare the Z-factors calculated by the correction functions with those calculated by the Peng-Robinson equation of state (PR-EOS) and with measured data published in the literature. The comparison results indicated that the average absolute relative deviation (AARD) is 3% for gas mixtures, 2% for pure hydrocarbon, non-hydrocarbon gases and less than 1% for pure components (methane, nitrogen, carbon dioxide). A stable method of calculating Z-factor for gases from their composition is presented. This method is iteration free so the CPU time is minimized. Accurate values of Z-factor can be calculated which are better than those obtained by linear interpolations. The correction functions can be incorporated in any non-compositional simulator to calculate the Z-factor directly without any iterative procedures which occur in compositional simulators during the calculations of Z-factor using the equation of state. These functions also eliminate the inaccurate linear interpolations of tabulated Z-values, specially during calculations of Z-factor for gas mixtures, in non-compositional simulators. Introduction The compressibility factor is an important property for gases to calculate volume (material) of gases under given conditions (pressure, temperature). Also the Z-factor is important parameter to calculate other gas properties such as the formation volume factor and the coefficient of isothermal compressibility. It is important to calculate the Z-factor more accurately, specially for gas mixtures, in order to predict the volumetric gas behavior more reasonably. In compositional simulators the calculations of the Z-factor are accurate, but for every condition the cubic equation of state is solved for Z-factor. The solution procedure involves iterations such as in Newton Raphson method. These iterations and convergence checking procedure consumes, some times, a considerable part of CPU time for just calculating gas properties (Z-factor). The CPU time should be used more efficiently in and wisely in the simulator. On the other side in the non-compositional simulators the Z-factor values are tabulated for certain gas composition and pressures and a linear interpolation procedure is used to calculated those Z-factor values which are not listed in the table. This procedure leads to erroneous calculations of Z-factor specially for gas mixtures where the linear interpolations are no longer accurate. The calculation procedure of Z-factor using the correlation functions presented in this paper has two advantages: Obtaining an accurate value of Z-factor and saving CPU time for other more important calculations in the simulator. Background Some impurities such as nitrogen and carbon dioxide are often existed in appreciable amounts in natural gases. The Z-factor for non-hydrocarbon components of natural gas in certain corresponding states differ markedly from those of hydrocarbons. This makes the non-hydrocarbon and hydrocarbon components not quit additive. Eilerts, Muller and Carlson studied the compressibility of natural gas and nitrogen mixtures. They proposed a method to calculate the Z-factor for the gas mixture by introducing a correction factor into the additive form as shown in Eq. 1. (1) where: Zm = actual Z-factor for gas mixture, Zn = Z-factor of the nitrogen in the mixture, Zn = Z-factor of hydrocarbon gas, n = mole fraction of nitrogen in the mixture. P. 453^

ABSTRACTThe current approach envisioned to fabricate targets for inertial fusion energy power plants is diffusion of a deuterium-tritium (D-T) gas mixture through the walls of the plastic shell targets at very high pressures (peaking at values up to 128 MPa) and modest temperatures (∼ 400 K). The use of high gas pressure during fabrication is required so that the D-T gas rapidly diffuses into the pellet, which enables the fabrication facility to satisfy the power plant’s fueling requirements. D-T gas mixtures at such high pressures raise safety concerns that must be addressed in the design. The combustion of D and T in air is discussed in this paper, as well as high pressure gas hazards and possible means to mitigate these hazards. The US Department of Energy guidance on tritium handling and storage is summarized here. Issues of safety and reliability of various protection systems are also discussed to support designers in tradeoff analyses of confnement types.

Corrosion in deep high pressure sour gas wells can be successfully controlled. Many problems have been encountered in producing Shell's high pressure sour gas wells producing Shell's high pressure sour gas wells in the Thomasville, Piney Woods, and Southwest Piney Woods Fields. Corrosion was one of these Piney Woods Fields. Corrosion was one of these major problems. A hole developed in the tubing of one well approximately five months after production was started and a hole developed in a second well shortly thereafter in spite of continuous inhibition. This paper briefly describes both the successful inhibition program that has been developed since these initial failures and the potential for improved inhibition systems. The cost in workovers, lost wells, and operating expenses since the initiation of production of these wells has been $28 million production of these wells has been $28 million greater than it would have been if the current inhibition system would have been available when production was initiated. production was initiated Introduction The purpose of this paper is to review the characteristics of a successful corrosion prevention system used in Shell's deep, high pressure, high hydrogen sulfide gas production in Mississippi. However, some introductory material is in order before corrosion prevention technique and corrosion prevention results are reviewed. prevention results are reviewed. In 1969, Shell discovered the Thomasville Field about 15 miles Southwest of Jackson Mississippi. Currently, Shell produces approximately 100 millions cubic feet per day from the three adjacent fields Thomasville, Piney Woods, and Southwest Piney Woods to a sulfur recovery and gas dehydration plant. Further reference in this paper to "Thomasville" will refer to wells in these three in the Smackover formation between 19,700–22,250 feet and the initial bottom hole pressures range from 17,500 psi to 22,000 psi. The pressures range from 17,500 psi to 22,000 psi. The production at these fields in sour gas, and is production at these fields in sour gas, and is completely free of liquid hydrocarbons. The produced gas, in combination with produced water, is very corrosive; it contains between 28% and 46% hydrogen sulfide, between 3% and 8% carbon dioxide and between 51% and 65% methane; the gas contains trace amounts of ethane, nitrogen, and other sulfides. There are no hydrocarbon components heavier than ethane in the gas. Water production is about 6–8 barrels per million cubic feet of gas and salinity ranges from fresh to brackish. Each well is equipped with a circulating string (tubing) and does not have a packer (Figure 1). The casing is the pressure string. From the start of production, oil and inhibitor were circulated in production, oil and inhibitor were circulated in each well to prevent sulfur deposition and corrosion. In spite of continuous inhibition, severe corrosion caused two tubing strings to part and caused a hole in the third tubing string. The first hole in the tubing occurred in about five months after initiation of production. production. In an effort to explain the above failures and the current solution, 1) the corrosion mechanism, 2) Oil phase behavior, 3) Inhibition system, and 4) Inhibition results will be respectively discussed. The value of successful corrosion prevention and potential for improvements in sour gas inhibition potential for improvements in sour gas inhibition will also be reviewed. CORROSION MECHANISM The corrosion mechanism results in the forming of "scabs" of iron sulfide corrosion product. The formation of these "scabs" involves both the H2S and the chloride ion. The thin chloride film (see Figure 2) in an acid gas environment contains hydrochloric acid (HC1). The HC1 reacts with the tubular to form an iron chloride.