Natural Gas Composition Research Articles

Technology Focus: Flow Assurance (November 2024)

This year’s Flow Assurance Technology Focus provides a trio of papers, selected by ChampionX’s Celestina Kissi, concerning the use of advanced techniques in detection, mitigation, and risk calculation. SPE technical conferences and meetings remain a critical conduit for the transfer of forward-thinking research and insight to both project developers and field practitioners who make certain that production is optimized and that goals are met. Paper SPE 216216 investigates asphaltene risks inherent in the gas-injection enhanced oil recovery (EOR) process. The authors’ research identifies what they term “stealth” asphaltenes, referring to asphaltenes detectable only by laser-light-scattering techniques and not by traditional microscopy. These asphaltenes are still flowable and can still pose risks to flow assurance. In the second selection, SPE 218101, the authors delve into the risks posed by hydrate formation in water-alternating-gas EOR operations, particularly during changeover operations, an area in need of further research in the literature. Additionally, the authors explore the effect of natural gas composition on these phenomena. Finally, paper SPE 218700 describes an operator’s development and deployment of a suite of cloud-based digital-twin tools designed to provide online, real-time calculation of scale risk and barrier health on a well-by-well basis. The complete paper includes four diverse case studies in which the described toolkit proved its value. As the technology used in the field sharpens, it will simultaneously overcome long-standing obstacles and discover entirely new ones, such as the challenge posed in the first presented paper. SPE technical conferences will continue to ensure that the flow of innovation reaches the page and the field with equal effect.

Differences in the Genesis and Sources of Hydrocarbon Gas Fluid from the Eastern and Western Kuqa Depression

The Kuqa Depression is rich in oil and gas resources and serves as a key production area in the Tarim Basin. However, controversy persists over the genesis of oil and gas in the various structural zones of the Kuqa Depression. This study employs natural gas composition analysis, gas carbon isotope analysis and gold pipe thermal simulation experiments, to comprehensively analyze the differences in the genesis and sources of hydrocarbon gas fluid from the eastern and western Kuqa Depression. The results show that the Kuqa Depression is dominated by alkane gas, with an average gas drying coefficient of 95.6, with nitrogen and carbon dioxide as the primary non-hydrocarbon gases. The average of δ13C1, δ13C2 and δ13C3 values in natural gas are −27.70‰, −20.43‰ and −21.75‰, respectively. Based on comprehensive natural gas geochemical maps, the CO2 in the natural gas from the Tudong and Dabei areas, as well as the KT-1 well of the Kuqa Depression, is thought to be of organic origin. Additionally, natural gas formation in the Tudong area is relatively simple, consisting entirely of thermally generated coal gas derived from the initial cracking of kerogen. The natural gas in the KT-1 well and the Dabei area are mixed gasses, formed by the initial cracking of kerogen from highly evolved lacustrine and coal-bearing source rocks, exhibiting characteristics resembling those of crude oil cracking gas. The methane (CH4) content of natural gas in the Dabei area is high and the carbon isotopes are unusually heavy. Considering the regional geological background, potential source rock characteristics and geochemical features may be related to the large-scale invasion of dry gas contributed by CH4 from highly evolved, underlying coal-bearing source rocks. Consequently, the CH4 content in the mixed gas is generally high (Ln (C1/C2) can reach up to 5.38), while the relative content of heavy components is low, though remains relatively unchanged. Thus, the map of the relative content of heavy components still reflects the characteristics of the original gas genesis (initial cracking of kerogen). Mixed-source gas was analyzed using thermal simulation experiments and natural gas composition ratio diagrams. The contributions of natural gas from deep, highly evolved coal-bearing source rocks in the KT-1 well and the Dabei area accounted for more than 90% and approximately 60%, respectively. This analysis provides theoretical guidance for natural gas exploration in the research area.

Characteristics and Origin of Natural Gas in Yongfeng Sub-Sag of Bogda Mountain Front Belt

By systematically analyzing the natural gas composition, carbon isotopes, and source rock characteristics in the Yongfeng sub-sag of the Bogda Mountain front belt, natural gas characteristics were determined, and the genetic types and sources of natural gas were investigated. The research results indicate that methane is the main component of natural gas in the Yongfeng sub-sag, with low levels of heavy hydrocarbons and a high drying coefficient. These characteristics make it dry gas, which refers to natural gas with a methane content of over 95%. The ethane carbon isotope δ13C2 of natural gas is −28.5‰ and belongs to oil type gas. The methane carbon isotope δ13C1 of natural gas is −58.6‰~−59.4‰, has a relatively depleted methane carbon isotope value, shows significant differences from the surrounding natural gas methane carbon isotope, and belongs to the category of biogenic gas. The Permian Lucaogou Formation is the main source rock in the study area, with good organic matter abundance. The microscopic components of kerogen are mainly composed of sapropelic formations and the organic matter type is I–II1. The source rock has a high maturity and has reached the mature stage, mainly consisting of oil and wet gas. The ethane carbon isotope of natural gas in the Yongfeng sub-sag shows as oil type gas, which is consistent with the kerogen type of the Lucaogou Formation source rocks, indicating that the natural gas mainly comes from the Lucaogou Formation source rocks. Based on comprehensive data and information on natural gas composition, carbon isotopes, and burial history of the source rocks, it is believed that some of the crude oil generated from the Lucaogou Formation in the early stage underwent biodegradation due to tectonic uplift, resulting in biogenic methane and the formation of crude oil biodegraded gas.

Investigating the Effect of Natural Gas Composition on Centrifugal Gas Compressors Used in Gas Turbine Power Plants

Investigating the Effect of Natural Gas Composition on Centrifugal Gas Compressors Used in Gas Turbine Power Plants

Numerical Analysis of Hydrogen-Enriched Natural Gas on Combustion and Emission Characteristics

AbstractThe integration of hydrogen into natural gas infrastructure presents a viable strategy for mitigating greenhouse gas emissions and advancing toward carbon neutrality. This study investigates the combustion characteristics and emissions profiles of hydrogen-enriched natural gas mixtures, specifically focusing on the composition of Russian pipeline natural gas. A comprehensive mathematical model was developed to predict emission concentrations and simulate fuel mixture combustion using MATLAB Simulink software. This versatile model facilitates further analysis within the MATLAB ecosystem. The simulation results demonstrate a significant correlation between the hydrogen content in the natural gas mixture and the resulting heat power output. With a constant fuel consumption rate, a notable decrease in heat power was observed as the hydrogen concentration increased, reaching a maximum reduction of 44.9% at a 45% hydrogen content. These findings underscore the feasibility of partially substituting natural gas with hydrogen, while also highlighting the necessity for increased fuel flow rates to maintain equivalent power output levels. This poses additional challenges for natural gas grid operators, necessitating infrastructure adaptations to accommodate higher fuel demands. The insights gained from this research contribute to the growing body of knowledge surrounding hydrogen integration in the energy sector, offering valuable implications for decarbonization strategies and the optimization of natural gas infrastructure.

Geochemical Characteristics and Origin of Natural Gas in the Middle of Shuntuoguole Low Uplift, Tarim Basin: Evidence from Natural Gas Composition and Isotopes

Multiple types of reservoirs, including volatile oil reservoirs, condensate gas reservoirs, and dry gas reservoirs, have been discovered in ultra-deep layers buried at depths greater than 7500 m. Understanding the genetic types of natural gas is of utmost importance in evaluating oil and gas exploration potential. The cumulative proved reserves of the super deep layer in the Shuntuoguole low uplift area of the Tarim Basin exceed 1 × 108 t (oil equivalent). The origin, source, and accumulation characteristics of natural gas still remain a subject of controversy. By analyzing the composition and carbon isotope of natural gas, a detailed investigation was conducted to examine the unique geochemical and reservoir formation characteristics of the Ordovician ultra-deep natural gas within different fault zones in the middle region of the Shuntuoguole low uplift. It was determined that most of the natural gas in this area is displaying a characteristic of wet gas with a drying coefficient ranging from 0.41 to 0.99. The carbon isotope composition of methane in the gas reservoir shows relatively light values, ranging from −49.4‰ to −42‰. The carbon and hydrogen isotopes of the components are distributed in a positive order. The natural gas is oil type gas, which is derived from marine sapropelic organic matter and has a good correspondence with the lower Yuertusi formation. The maturity of natural gas in Shunbei No. 1 and No. 5 fault zones is about 1.0%, which is the associated gas of normal crude oil, while the maturity of No. 4 and No. 8 fault zones is higher than 1.0%, which is the mixture of kerogen pyrolysis gas and crude oil pyrolysis gas. The variations in the drying coefficient and carbon isotope composition of the natural gas provide evidence for the migration patterns within the Shuntuoguole low uplift central region. It indicates that the Shunbei No. 5 and No. 8 fault zones have likely migrated from south to north, while the No. 4 fault zone has migrated from the middle to both the north and south sides. These migration patterns are primarily controlled by high and steep strike-slip faults, which facilitate the vertical migration of natural gas along fault planes. Consequently, the gas accumulates in fractured and vuggy reservoirs within the Ordovician formation.

Gas Composition Tracking in a Transient Pipeline Using the Method of Characteristics

For a gas pipeline with multiple gas sources, the significance of tracking the composition of natural gas is increasing with the implementation of X+1+X system for the natural gas industry in China. Mathematically, the tracking problem is usually described by a system of partial differential equations (PDEs). The continuity equation on gas composition has been developed to track natural gas composition according to the law of mass conservation. The algorithm resulting from the method of characteristics (MOC) is proposed to solve the system of PDEs. Compared to the original MOC, numerical solutions of the continuity equation on gas composition are obtained after the hydraulic calculation and thermal calculation. Moreover, different combinations of boundary conditions for the MOC are derived, which could expand the range of application of the MOC and be applicable to various operating conditions. The heating values of diverse gas sources have been determined following the methods documented in ISO 6976:2016. The case study of a gas pipeline in China verified the validity of the algorithm via the commercial simulation software Pipeline Studio for Gas (TGNET). The heating value and gas composition obtained by the algorithm can be used in the custody transfer metering of natural gas pipelines for Class B and C metering stations described in GB/T 18603−2014.

Influence of Natural Gas Composition and Operating Conditions on the Steady-State Performance of Dry Gas Seals for Pipeline Compressors

Influence of Natural Gas Composition and Operating Conditions on the Steady-State Performance of Dry Gas Seals for Pipeline Compressors

Influence of natural gas component changes on hydrate generation temperature and pressure

Abstract During the transportation of natural gas through pipelines, there is a potential for the formation of gas hydrates. These hydrates can result in pipeline blockages, causing economic losses and significant safety hazards. Therefore, it holds crucial reference value to understand the conditions under which hydrates are formed and to grasp the laws governing their generation for effective prevention and control. This study employs the P-P hydrate thermodynamic model to compute the temperature and pressure at which natural gas generates hydrates. We also explore the impact of changes in the composition of natural gas on the temperature and pressure required for hydrate formation. This helps us discern the sensitivity of hydrate formation conditions to various components. Our findings indicate that propane, isobutane, and H2S substantially influence hydrate formation under the same percentage of alteration. For instance, a 3% increase in these three components results in a temperature increase of 2.36°C, 2.83°C, and 2.14°C, respectively, for hydrate formation at 100 bar.

Natural gas exploration potential and favorable targets of Permian Fengcheng Formation in the western Central Depression of Junggar Basin, NW China

Based on the organic geochemical data and the molecular and stable carbon isotopic compositions of natural gas of the Lower Permian Fengcheng Formation in the western Central Depression of Junggar Basin, combined with sedimentary environment analysis and hydrocarbon-generating simulation, the gas-generating potential of the Fengcheng source rock is evaluated, the distribution of large-scale effective source kitchen is described, the genetic types of natural gas are clarified, and four types of favorable exploration targets are selected. The results show that: (1) The Fengcheng Formation is a set of oil-prone source rocks, and the retained liquid hydrocarbon is conducive to late cracking into gas, with characteristics of high gas-generating potential and late accumulation; (2) The maximum thickness of Fengcheng source rock reaches 900 m. The source rock has entered the main gas-generating stage in Penyijingxi and Shawan sags, and the area with gas-generating intensity greater than 20×108 m3/km2 is approximately 6 500 km2. (3) Around the western Central Depression, highly mature oil-type gas with light carbon isotope composition was identified to be derived from the Fengcheng source rocks mainly, while the rest was coal-derived gas from the Carboniferous source rock; (4) Four types of favorable exploration targets with exploration potential were developed in the western Central Depression which are structural traps neighboring to the source, stratigraphic traps neighboring to the source, shale-gas type within the source, and structural traps within the source. Great attention should be paid to these targets.

Downstream natural gas composition across U.S. and Canada: implications for indoor methane leaks and hazardous air pollutant exposures

Previous research has shown that natural gas (NG) leaks from residential appliances are common, affecting greenhouse gas emission inventories and indoor air quality. To study these implications, we collected and analyzed 587 unburned NG samples from 481 residences over 17 North American cities for hydrocarbons, hazardous air pollutants, and organosulfur odorants. Nearly all (97% of) gas samples contained benzene (between-city mean: 2335 ppbv [95% CI: 2104, 2607]) with substantial variability between cities. Vancouver, Los Angeles, Calgary, and Denver had at least 2x higher mean benzene concentrations than other cities sampled, with Vancouver exhibiting a nearly 50x greater mean benzene level than the lowest-concentration city (Boston). We estimate that current U.S. and Canadian emissions inventories are missing an additional 25 000 [95% CI: 19 000, 34 000] and 4000 [95% CI: 3700, 5200] lbs benzene yr−1 through downstream NG leakage, respectively. Concentrations of odorants added for leak detection varied substantially across cities, indicating a lack of standardization. Houston, for instance, had 5x higher mean tert-butyl mercaptan levels than Toronto. Using these odorant measurements, we found that methane emissions as high as 0.0080–0.28 g h−1 and indoor benzene enhancements 0.0096–0.11 ppbv could go undetected by persons with an average sense of smell, with large uncertainties driven by smelling sensitivity, gas composition, and household conditions. We also observed larger leaks (>10 ppm ambient methane) in ∼4% of surveyed homes, confirming that indoor leakage occurs at varying degrees despite the presence of odorants. Overall, our results illustrate the importance of downstream NG composition to understand potential emissions, exposures, and odor-mediated leak detection levels. Given methane’s global warming potency, benzene’s toxicity, and wide variation in smelling abilities, our findings highlight the deficiencies regarding the sole reliance on odorization to alert and protect all occupants from indoor leaks.

A Review on Natural Gas Origin and Composition

Natural gas is obtained naturally. It is a hydrocarbon mixture. Natural gas is clean fossil fuel. It is safe when transported. Methane is main constituent of natural gas. It may also contain higher order hydrocarbons, carbon dioxide, helium, hydrogen sulphide and noble gases. World is facing problem of environmental pollution. To combat menace of pollution alternative sources of energy should be used. Natural gas is the cleanest fuel. Demand of natural gas all over the world is increasing.

Design modification and comparative analysis of glycol‐based natural gas dehydration plant

AbstractNatural gas production from reservoirs is often associated with water, which poses numerous challenges, such as methane hydrate formation, sludge, corrosion and flow assurance issues in gas processing plants and sales gas transmission pipelines. To effectively remove water from natural gas, there is a need to design, compare and modify dehydration plants. This study investigated the performance difference between a conventional triethylene glycol (TEG)‐based dehydration system with a cooler at the TEG inlet to the contactor, and a newly proposed TEG‐based dehydration system with a heat exchanger replacing the cooler at the TEG inlet with the contactor. The advanced process simulation software Aspen HYSYS was used to design and compare two dehydration system configurations. The modified design configuration exhibited better performance in terms of energy conservation and water‐removal capability. The material balance of molar flow, mass flow and volume flow of dry gas produced in the absorber/contactor column showed a higher volume of dry gas produced in the modified system configuration, indicating that it is a better design. The modified design configuration also produced dry gas within the recommended temperature range for underground storage and transmission. There was a significant difference in the percentage difference of 64% between the conventional and modified designs in terms of energy consumption, whereas the percentage differences of 0% and 0.6% showed nonsignificant and significant differences between the two plant design configurations. Both plant design configurations showed a significant reduction (from 0.005 to 0.0002 mol%) in the water composition of natural gas after the simulation.

Tracing of natural gas migration by light hydrocarbons: A case study of the Dongsheng gas field in the Ordos Basin, NW China

Based on the analysis of light hydrocarbon compositions of natural gas and regional comparison in combination with the chemical components and carbon isotopic compositions of methane, the indication of geochemical characteristics of light hydrocarbons on the migration features, dissolution and escape of natural gas from the Dongsheng gas field in the Ordos Basin is revealed, and the effect of migration on specific light hydrocarbon indexes is further discussed. The study indicates that, natural gas from the Lower Shihezi Formation (P1x) in the Dongsheng gas field displays higher iso-C5−7 contents than n-C5−7 contents, and the C6−7 light hydrocarbons are composed of paraffins with extremely low aromatic contents (<0.4%), whereas the C7 light hydrocarbons are dominated by methylcyclohexane, suggesting the characteristics of coal-derived gas with the influence by secondary alterations such as dissolution. The natural gas from the Dongsheng gas field has experienced free-phase migration from south to north and different degrees of dissolution after charging, and the gas in the Shiguhao area to the north of the Borjianghaizi fault has experienced apparent diffusion loss after accumulation. Long-distance migration in free phase results in the decrease of the relative contents of the methylcyclohexane in C7 light hydrocarbons and the toluene/n-heptane ratio, as well as the increase of the n-heptane/methylcyclohexane ratio and heptane values. The dissolution causes the increase of isoheptane values of the light hydrocarbons, whereas the diffusion loss of natural gas in the Shiguhao area results in the increase of n-C5−7 contents compared to the iso-C5−7 contents.

The Influence of the Changes in Natural Gas Supplies to Poland on the Amount of Hydrogen Produced in the SMR Reactor

Thanks to investments in diversifying the supply of natural gas, Poland did not encounter any gas supply issues in 2022 when gas imports from Russia were ceased due to the Russian Federation’s armed intervention in Ukraine. Over the past few years, the supply of gas from routes other than the eastern route has substantially grown, particularly the supplies of liquefied natural gas (LNG) via the LNG terminal in Świnoujście. The growing proportion of LNG in Poland’s gas supply leads to a rise in ethane levels in natural gas, as verified by the review of data taken at a specific location within the gas system over the years 2015, 2020, and 2022. Using measurements of natural gas composition, the effectiveness of the steam hydrocarbon reforming process was simulated in the Gibbs reactor via Aspen HYSYS. The simulations confirmed that as the concentration of ethane in the natural gas increased, the amount of hydrogen produced, and the heat required for reactions in the reformer also increased. This article aims to analyze the influence of the changes in natural gas quality in the Polish transmission network caused by changes in supply structures on the mass and heat balance of the theoretical steam reforming reactor. Nowadays, the chemical composition of natural gas may be significantly different from that assumed years ago at the plant’s design stage. The consequence of such a situation may be difficulties in operating, especially when controlling the quantity of incoming natural gas to the reactor based on volumetric flow without considering changes in chemical composition.

Geochemistry of Liquid Hydrocarbons and Natural Gases Combined with 1D Basin Modeling of the Oligocene Shale Source Rock System in the Offshore Nile Delta, Egypt.

The current study aims to integrate the geochemical characteristics of the Oligocene shale source rock system, oil, condensate, and natural gas samples in the Oligocene sandstone reservoirs from three exploration wells located in the offshore Nile Delta, East Mediterranean Sea, using organic geochemistry and a 1D basin modeling scheme. The Tineh shales exhibit total organic carbon values ranging between 0.90 and 1.89 wt %, along with hydrogen index values in the range of 54-240 mg hydrocarbon/g rock. The geochemical characterization suggests that the shale intervals of the Oligocene Tineh Formation contain type II-III and type III kerogens and, thereby, could be regarded as promising oil- and gas-prone source rocks with high contributions of gas generation potential. The study also reconstructs the 1D thermal and burial history models, showing that the Oligocene Tineh source rock system is in the main oil and wet gas generation phases from the late Miocene to the present time. The simulated basin models reveal the transformation (TR) of 10-50% kerogen to oil during the late Miocene-early Pliocene period and that the Oligocene Tineh source rock system has larger oil generation and expulsion competency, with a TR value of up to 65% during the early Pliocene-Pleistocene time period. The thermogenic gas was also formed during this time and continued to the present day. This study also investigated the presence of oil and condensate in the Oligocene sandstone reservoir samples and revealed that they were generated from mature source rock, ranging from moderately to highly mature stages. This source rock unit was deposited in fluvial to fluvial-deltaic environments under oxic mixed organic conditions and accumulated during the Tertiary time, as evidenced by the presence of the oleanane biomarker dating indicator. The molecular and isotope compositions of natural gases revealed that most of the natural gases in the Oligocene sandstone reservoir are mainly thermogenic methane gases that were generated from mainly mixed organic matter. The thermogenic methane gases were formed mainly from secondary cracking of oil and gas, with small contributions of primary kerogen cracking. The properties of natural gases together with oil and condensate in the Oligocene reservoir rocks suggest that most of the thermogenic methane gases and associated liquid hydrocarbons are derived primarily from the Oligocene shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking in different thermal maturity stages. Therefore, the Oligocene Tineh Formation can be regarded as self-source generation and self-reservoir rock; hence, an intensive oil exploration and production program can be recommended whenever the Tineh source rock system is is well developed and deeply buried.

Hydrate-based technique for natural gas processing: Experimental study of pressure-dropping and continuous modes

Gas hydrate crystallization is perspective and energy-efficient technology for gas mixtures processing, including natural gas. There were compared pressure-dropping and continuous gas hydrate crystallization methods for separation of gas mixture closed to natural gas. The studied mixture has been chosen similar to the natural gas composition: CH4 (75.68 mol.%) - С2H6 (7.41 mol.%) - C3H8 (4.53 mol.%) - н-C4H10 (2.47 mol.%) - CO2 (5.40 mol.%) - H2S (1.39 mol.%) - N2 (3.01 mol.%) - Xe (0.11 mol.%). Experiments were provided in the 4 L high pressure reactor, using water solution of SDS (0.20 wt.%). The experiment conditions were 280.15 K and pressure of 4.25 MPa. The components separation factors and recovery for two modes have been researched and compared for choosing more effective options. After comparing these characteristics, it was concluded that continuous process is more productive than pressure-dropping mode. At the stage cut (θ) of 0.9, the gas components total recovery (R) for the continuous mode have exceeded the total recovery for the pressure-dropping mode by 8.15 %, and at θ = 0.8, exceeded by 6.11 %. The recovery and separation factors have the highest values for H2S, C3H8, Xe in the continuous mode: 97.62 %, 94.90 %, 84.98 % and 8.7, 10.53, 6.36, respectively. Thus, the choosing of the more effective stage cut depends on the aim of the process: the highest purity or the largest recovery.

Hydrate phase equilibrium conditions for H2S and CO2 gas mixture removal from natural gas: modeling and optimization study

In this study, for the first time, a comprehensive mathematical modeling of the optimal conditions for the gas hydrates formation of hydrogen sulfide (H2S) and carbon dioxide (СО2) was carried out with the aim of them removing from natural gas. The study was carried out on a model gas mixture close to the natural gas composition: CH4 – C2H6 – С3Н8 – n-С4Н10 – СО2 – H2S – N2. A temperature range of 268.15–283.15 К and a pressure range of 2.00–8.00 MPa were investigated. The efficiency was assessed based on the gas hydrate distribution coefficients. It was found that the gas hydrate extraction of H2S is more significantly affected by the concentration of H2S in the initial gas mixture. The gas hydrate extraction of СО2 is more significantly affected by the temperature and pressure of the gas separation unit. The maximum gas hydrate distribution coefficient of H2S is 42.05 at T = 268.15 K, p = 8.00 MPa. The maximum gas hydrate distribution coefficient of СО2 is 0.49 at T = 283.15 K, p = 8.00 MPa. Due to the small amounts of CO2 entrapped in gas hydrates, a scheme that combines a multi-stage hydrate-based and membrane technology has been suggested to purify natural gas further.

Optimization of adiabatic flame temperature of natural gas combustion under different conditions

AbstractThe combustion of natural gas consisted of methane , ethane , and propane is theoretically investigated to obtain the optimum adiabatic flame temperature (AFT). The investigation includes the development of combustion equations that take into consideration different compositions of natural gas. The final equation to calculate the AFT is derived and used in the optimization study. The optimization study using genetic algorithm investigates the effect of changing the composition of the gas mixture, the inlet temperature of used air, and the amount of excess air used on the AFT. It is possible to get the required composition of each component, the air inlet temperature, and the excess air by reading the chart to get the required AFT. The heat capacity of all reactants and products is used as a function of temperature. Results showed that the optimum values for , percentages in the gas mixture, air inlet temperature, and the amount of excess air are 0.478, 0.166, 0.356 mol %, 1.848, 382.104 K, respectively. These optimum values lead to a value of about 1300 K for the AFT. The derived equation shows the AFT at different natural gas compositions along with different process parameters such as the amount of excess air. Thus, the required combustion temperature can be controlled by adjusting the natural gas composition or the combustion temperature can be specified based on the provided composition of the natural gas stream by using either the derived equations or output chart. (R1. 1).

Use of near-infrared spectroscopy for the online monitoring of natural gas composition (hydrocarbons, water and CO2 content) at high pressure

The natural gas production from Brazilian pre-salt fields imposed new challenges for petrochemical industry. Actual treatment facilities are not adequate for this new scenario and studies have been conducted to apply new adsorbents materials and membranes for water and CO2 removal from natural gas at high pressures. To better develop such investigations, sensors for on-line monitoring of natural gas properties like CO2 and water content are important, since their presence affects the quality of the final product. Near infrared (NIR) spectroscopy associated to chemometric models (partial least squares) were employed for on-line monitoring of representative natural gas systems (methane/CO2, methane/water and methane/CO2/water) and a real natural gas at temperature and pressure ranges from 20 to 60 °C and 10 to 200 bar, respectively, water content up to gas saturation and CO2 content up to 50 wt%. Water solubility values used as reference for NIR Spectrometer calibration in model systems were taken from the literature and for real natural gas calculated with Cubic Plus Association (CPA) Equation of State (EoS), while CO2 content was experimentally controlled aiming to calibrate the chemometric models in the full range of pressure and temperature. Several strategies were adopted for the chemometric model’s development to obtain the best correlation between NIR spectra and experimental data. Results indicate good correlation in both calibration and validation steps attaining linear correlation coefficients (R2) higher than 0.96 for all systems investigated. The proposed methodology is a potential tool for on-line monitoring of natural gas composition, including CO2 and water content, at high-pressures and can be applied at petrochemical industries or in laboratories, dispensing sampling or any sample preparation.