Characterisation of rare earth elements in natural and exhaust gas samples: SEM-microscopy and EDX-analysis for source identifications

The U.S. Department of Energy (DOE) Office of Legacy Management conducted hydrologic and natural gas sampling for the Gasbuggy, New Mexico, site on June 16, and 17, 2009. Hydrologic sampling consists of collecting water samples from water wells and surface water locations. Natural gas sampling consists of collecting both gas samples and samples of produced water from gas production wells. The water well samples were analyzed for gamma-emitting radionuclides and tritium. Surface water samples were analyzed for tritium. Water samples from gas production wells were analyzed for gamma-emitting radionuclides, gross alpha, gross beta, and tritium. Natural gas samples were analyzed for tritium and carbon-14. Water samples were analyzed by ALS Laboratory Group in Fort Collins, Colorado, and natural gas samples were analyzed by Isotech Laboratories in Champaign, Illinois. Concentrations of tritium and gamma-emitting radionuclides in water samples collected in the vicinity of the Gasbuggy site continue to demonstrate that the sample locations have not been impacted by detonation-related contaminants. Results from the sampling of natural gas from producing wells demonstrate that the gas wells nearest the Gasbuggy site are not currently impacted by detonation-related contaminants. Annual sampling of the gas production wells nearest the Gasbuggy site for gas and produced water will continue for the foreseeable future. The sampling frequency of water wells and surface water sources in the surrounding area will be reduced to once every 5 years. The next hydrologic sampling event at water wells, springs, and ponds will be in 2014.

Accretionary prisms are thick layers of sedimentary material piled up at convergent plate boundaries. Large amounts of anaerobic groundwater and methane (CH4) are contained in the deep aquifers associated with accretionary prisms. In order to identify microbial activity and CH4 production processes in the deep aquifers associated with the Cretaceous accretionary prism in Okinawa Island, Japan, we performed geochemical and microbiological studies using anaerobic groundwater and natural gas (mainly CH4) samples collected through four deep wells. Chemical and stable hydrogen and oxygen isotope analyses of groundwater samples indicated that the groundwater samples obtained from each site originated from ancient seawater and a mixture of rainwater and seawater, respectively. Additionally, the chemical and stable carbon isotopic signatures of groundwater and natural gas samples suggested that CH4 in the natural gas samples was of a biogenic origin or a mixture of biogenic and thermogenic origins. Microscopic observations and a 16S rRNA gene analysis targeting microbial communities in groundwater samples revealed the predominance of dihydrogen (H2)-producing fermentative bacteria and H2-utilizing methanogenic archaea. Moreover, anaerobic cultures using groundwater samples suggested a high potential for CH4 production by a syntrophic consortium of H2-producing fermentative bacteria and H2-utilizing methanogenic archaea through the biodegradation of organic substrates. Collectively, our geochemical and microbiological data support the conclusion that the ongoing biodegradation of organic matter widely contributes to CH4 production in the deep aquifers associated with the Cretaceous accretionary prism.

The origin and secondary alteration of dissolved gas in oil: A case study from the western Tu-Ha Basin, China

A reconnaissance study of 13C–13C clumping in ethane from natural gas

Mantle-derived noble gases in natural gases from Songliao Basin, China

World experience shows that important factor in the calculations for natural gas consumption between suppliers and consumers is not only the volume of natural gas, but the quality indicators. With gas market liberalization, gas properties are expected to vary more frequently and strongly (composition, heating value etc.). Quality of natural gas is currently a topical issue, considering the steady increase of gas consumption in the world in recent decades. Existent chromatographs and calorimeters are very accurate in gas quality determination, but general expenditure and maintenance costs are still considerable. Market demands alternative lower cost methods of natural gas quality determination for transparent energy billing and technological process control. Investigation results indicate that heating value (HV) is a nonlinear function of such parameters as sound velocity in gas, N2 and CO2 concentration. Those parameters show strong correlation with natural gas properties of interest (HV, density, Wobbe index), during analysis conducted on natural gas sample database. For solving nonlinear multivariable approximation task of HV determination, artificial neural networks were used. Proposed approach allowed excluding N2 concentration from input parameters with maintenance of sufficient accuracy of HV determination equal to 3.7% (with consideration of N2 concentration – 2.4%) on sample database. For validating of received results corresponding experimental investigation was conducted with reference analysis of physical and chemical parameters of natural gas samples by gas chromatography and followed superior HV calculation according to ISO 6976:1995. Developed experimental setup consist of measuring chamber with ultrasonic transducer, reflector, pressure, temperature and humidity sensors, ultrasonic inspection equipment for sound velocity measurements and CO2 concentration sensor with relevant instrument. The experimental setup allows measurement of sound velocity at 1MHz frequency and CO2 concentration in natural gas sample along with parameters control (temperature, humidity, pressure). The HV calculation algorithm was based on specially designed and trained artificial neural networks. Experimental investigation of proposed approach was conducted on 40 real samples of locally distributed natural gas. Obtained results, in comparison to reference values, showed absolute error in Lower HV (net calorific value) determination equal 166 kJ/m3, while relative error was equal 4.66%. Developed technology allows construction of autonomous instrument for instant natural gas quality determination, which can be combined with volume meters in order to provide transparent energy flow measurement and billing for gas consumers. Additionally it can be used for gas sensitive technological process control.

Compressibility factor measurement and simulation of five high-temperature ultra-high-pressure dry and wet gases

Organic arsenic compounds (trialkylarsines) present in natural gas were extracted by 10 cm3 of concentrated nitric acid from 1 dm3 of gas kept at ambient pressure and temperature. The flask containing the gas and the acid was shaken for 1 h on a platform shaker set at the highest speed. The resulting solution was mixed with concentrated sulfuric acid and heated to convert all arsenic compounds to arsenate. Total arsenic was determined in the mineralized solutions by hydride generation. The arsenic concentrations in natural gas samples from a number of wells in several gas fields were in the range 0.01–63 μ As dm−3. Replicate determinations of arsenic in a gas sample with an arsenic concentration of 5.9 μ dm−3 had a relative standard deviation of 1.7%. Because of the high blank values, the lowest arsenic concentration that could be reliably determined was 5 ng As dm−3 gas. Analysis of nonmineralized extracts by hydride generation identified trimethylarsine as the major arsenic compound in natural gas. Low‐temperature gas chromatography‐mass spectrometry showed more directly than the hydride generation technique, that trimethylarsine accounts for 55–80% of the total arsenic in several gas samples. Dimethylethylarsine, methyldiethylarsine, and triethylarsine were also identified, in concentrations decreasing with increasing molecular mass of the arsines.

Determination of intermolecular and intramolecular isotopic compositions of low-abundance gaseous hydrocarbons using an online hydrocarbon gas concentration method

Development of new method of δ13C measurement for trace hydrocarbons in natural gas using solid phase micro-extraction coupled to gas chromatography isotope ratio mass spectrometry

This field study employs multiple methods to detect the potential migration of natural gas and fluids from six hydraulically fractured, horizontal Marcellus Shale gas wells upward and into an overlying Upper Devonian gas field that is 3000-4000 ft above the Marcellus Shale but at least 3000 ft below underground sources of drinking water. Microseismic monitoring during the hydraulic fracturing of 56 stages located 10,288 events, including both event clusters and isolated events with maximum height above the Marcellus Shale of about 1900 ft and 2500 ft, respectively. Moment magnitudes ranged between -3.15 and -0.56. Assuming that the periphery of the microseismic event cloud represents the maximum possible extent of hydraulic fracture growth, the induced fractures do not extend to producing zones in the Upper Devonian gas field. This hypothesis is supported by pressure monitoring in the normally-pressured to under-pressured Upper Devonian gas reservoirs. No observed pressure increase in the Upper Devonian wells in the three-month period after hydraulic fracturing implies that there is no communication with the over-pressured Marcellus Formation below. Perfluorocarbon tracers were injected with hydraulic fracturing fluids into 10 stages (stages 5-14) of a 14-stage, horizontal Marcellus Shale gas well. For eight months after completion of the Marcellus Shale well, natural gas samples were collected from two vertical Upper Devonian wells that directly overlie the horizontal Marcellus Shale well where the tracers were injected. Perfluorocarbon tracers were not detected in sorbent tubes placed in the production lines from overlying wells (detection limit ≍ 1 femtoliter (fL)). Samples of gas and produced water were collected from five Upper Devonian gas wells that overlie the hydraulically fractured, horizontal, Marcellus Shale wells. Monthly sampling at these wells commenced two months prior to and has continued for nine months after hydraulic fracturing. Produced water samples were analyzed for major and trace ions, and for isotopes of strontium and lithium; natural gas samples were analyzed for isotopes of carbon and hydrogen. Isotopic analysis of natural gas from the Upper Devonian wells has shown no evidence of communication with the hydraulically fractured Marcellus Shale. Isotopic analysis of produced water samples from Upper Devonian gas wells is currently in progress, but incomplete.

Volatile arsenic compounds in natural gas, existing in the form of trimethylarsine (TMAs), have been determined using gas cryo-trapping gas chromatography coupled to inductively coupled plasma-mass spectrometry (CT-GC-ICP-MS). The results from a number of different gas wells revealed a huge concentration spread ranging from below the detection limit of 0.2 up to 1800 microg/m(3) TMAs (as As) in the gas. Due to the toxicity and corrosive nature of these arsines, they need near real time monitoring via a method that can easily be implemented on site, i.e. during gas exploitation. Here, we introduce a novel method which utilises silver nitrate impregnated silica gel tubes for quantitative chemotrapping of trimethylarsine (TMAs) from a natural gas matrix. Subsequent elution with hot nitric acid followed by online photo-oxidation hydride generation atomic fluorescence spectrometry (HG-AFS) is used for the determination of TMAs gas standards in nitrogen and natural gas samples, respectively. The chemotrapping method was validated using CT-GC-ICP-MS as a reference method. The recovery of arsenic from nitrogen or natural gas matrix ranged from 85 to 113% for a range of 20 to 2000 ng As. Trapping efficiency was >98%, from the methods LOD of 20 ng to 4.8 microg (absolute amount As) with sample sizes of 0.02 and 2 L gas. Method performance was established by comparing the results obtained for eight natural gas samples containing between 1 and 140 microg As/m(3) with those achieved by the reference method (CT-GC-ICP-MS).

To achieve a reliable method to calculate the hydrocarbon dew point for natural gases in transmission, samples of natural gas were taken at the inlet of the Magreb-Europe pipeline in Spain. The composition up to the C12 fraction of each natural gas sample was determined by gas chromatography, and the dew-point curve was measured using a chilled mirror dew-point analyzer. In this work, we present the experimental measurements of dew points for six samples of natural gas between 1.1 × 105 Pa and 78.4 × 105 Pa in the temperature range from 235.2 to 277.9 K. The experimental results obtained were analyzed in terms of a predictive excess function−equation of state (EF-EOS) method based on the zeroth-approximation of Guggenheim's reticular model. Because the EF-EOS model uses a group contribution model, the availability of every binary experimental data corresponding to every binary interaction in the mixture is not necessary. Considering this and the good results obtained in previous studies, we concluded that...

The U.S. Department of Energy (DOE) Office of Legacy Management conducted annual natural gas sampling for the Gasbuggy, New Mexico, Site on June 20 and 21, 2012. This long-term monitoring of natural gas includes samples of produced water from gas production wells that are located near the site. Water samples from gas production wells were analyzed for gamma-emitting radionuclides, gross alpha, gross beta, and tritium. Natural gas samples were analyzed for tritium and carbon-14. ALS Laboratory Group in Fort Collins, Colorado, analyzed water samples. Isotech Laboratories in Champaign, Illinois, analyzed natural gas samples.

Intramolecular 13C isotope distributions of butane from natural gases