scholarly journals Molecular and Carbon Isotopic Variation during Canister Degassing of Terrestrial Shale: A Case Study from Xiahuayuan Formation in the Xuanhua Basin, North China

Minerals ◽  
2021 ◽  
Vol 11 (8) ◽  
pp. 843
Author(s):  
Jia Tao ◽  
Jinchuan Zhang ◽  
Junlan Liu ◽  
Yang Liu ◽  
Wei Dang ◽  
...  
Keyword(s):  
Natural Gas ◽  
Carbon Isotope ◽  
Shale Gas ◽  
Small Variation ◽  
Source Rocks ◽  
Isotopic Variation ◽  
Carbon Isotopic ◽  
Geochemical Parameters ◽  
Shale Reservoirs ◽  
Isotope Variation

Molecular and carbon isotopic variation during degassing process have been observed in marine shale reservoirs, however, this behavior remains largely unexplored in terrestrial shale reservoirs. Here, we investigate the rock parameters of five terrestrial shale core samples from the Xiahuayuan Formation and the geochemical parameters of thirty natural gas samples collected during field canister degassing experiments. Based on these new data, the gas composition and carbon isotope variation during canister degassing are discussed and, further, the relationship between petrophysics and the carbon isotope variation is explored. The results show that methane content first increases and then decreases, the concentrations of carbon dioxide (CO2) and nitrogen gas (N2) peak in the early degassing stage, while heavier hydrocarbons gradually increase over time. Shale gas generated from humic source rocks contains more non-hydrocarbon and less heavy hydrocarbon components than that generated from sapropelic source rocks with similar maturity. Time-series sampling presents an upward increase in δ13C1 value during the degassing process with the largest variation up to 5.7‰, while the variation in δ13C3 and δ13C2 is insignificant compared to δ13C1. Moreover, we find that there is only a small variation in δ13C1 in shale samples with high permeability and relatively undeveloped micropores, which is similar to the limited δ13C1 variation in conventional natural gas. For our studied samples, the degree of carbon isotope variation is positively correlated with the TOC content, micropore volume, and micropore surface, suggesting that these three factors may play a significant role in carbon isotope shifts during shale gas degassing. We further propose that the strong 13C1 and C2+depletion of shale gas observed during the early degassing stage may have resulted from the desorption and diffusion effect, which may lead to deviation in the identification of natural gas origin. It is therefore shale gas of the late degassing stage that would be more suitable for study to reduce analytic deviations. In most samples investigated, significant isotopic variation occurred during the degassing stage at room temperature, indicating that the adsorbed gas had already been desorbed at this stage Our results therefore suggest that more parameters may need to be considered when evaluating the lost gas of shales.

The Research of Origin of Deep Natural Gas of Qianbei Sub-Sag in the South of Songliao Basin

2014 ◽  
Vol 675-677 ◽  
pp. 1341-1346
Author(s):  
Wu Yi ◽  
Wei Chao Tian
Keyword(s):  
Natural Gas ◽  
Analytical Data ◽  
Parent Material ◽  
Source Rocks ◽  
Gas Content ◽  
Carbon Isotopic ◽  
Hydrocarbon Source Rocks ◽  
Study Results ◽  
Humus Type ◽  
Hydrocarbon Gas

This paper analyses the origins of deep natural gas in Qianbei Subsag using a variety of analytical data such as the natural gas components, the isotope and the light hydrocarbon analysis combining with the development characteristics of hydrocarbon source rocks. The study results show as the following: The abundance of organic matter from hydrocarbon source rocks in Qianbei Subsag is high and dominated by humus type. Part of good hydrocarbon source rocks of Type II1 and Type II2 are developed in Yingcheng Formation and these are the major gas source rocks that is in the stage of postmaturity in evolution degree. The natural gas component is dominated by methane and non-hydrocarbon gas content is low. The isotope values of ethane are lighter and methane and ethane have an obvious phenomenon of carbon isotopic reversal. Parent material types of methane and ethane are from different sources. The sources of methane are biased to humic parent material while the sources of ethane are biased to sapropelic parent material.

scholarly journals Geochemical Characteristics of Gas and Flowback Water in Lake Facies Shale: A Case Study From the Junggar Basin, China

2021 ◽  
Vol 9 ◽  
Author(s):  
Lin Zhang ◽  
Dan Liu ◽  
Yongjin Gao ◽  
Min Zhang
Keyword(s):  
Carbon Isotope ◽  
Shale Gas ◽  
Isotope Composition ◽  
Ordos Basin ◽  
Junggar Basin ◽  
Source Rocks ◽  
Flowback Water ◽  
Lucaogou Formation ◽  
The Difference

The chemical and isotopic compositions of the natural gas and the co-produced flowback water from the XJC 1 well in Junggar Basin, China, were analyzed to determine the origin of gases in the Permian Lucaogou Formation (P2l) and the Triassic Karamay Formation (T2k) in the Bogda Mountain periphery area of the Southern Junggar Basin. The value of carbon isotope composition of the P2l lacustrine shale gas in the Junggar Basin was between the shale gas in Chang 7 Formation of Triassic (T1y7) in the Ordos Basin and that in the Xu 5 Formation of Triassic (T3x5) in the Sichuan Basin. The difference in gas carbon isotope is primarily because the parent materials were different. A comparison between compositions in the flowback water reveals that the P2l water is of NaHCO3 type while the T2k water is of NaCl type, and the salinity of the latter is higher than the former, indicating a connection between P2l source rock and the T2k reservoir. In combination with the structural setting in the study area, the gas filling mode was proposed as follows: the gas generated from the lacustrine source rocks of the Permian Lucaogou Formation is stored in nearby lithological reservoirs from the Permian. Petroleum was also transported along the faults to the shallow layer of the Karamay Formation over long distances before it entered the Triassic reservoir.

scholarly journals Petroleum Geochemistry Regional Study of Murzuq Basin: Insights from Biomarkers Characteristic, Stable Carbon Isotope and Environmental Characterization

2020 ◽  
Vol 4 (1) ◽  
pp. 1-14
Author(s):  
Aboglila S
Keyword(s):  
Carbon Isotope ◽  
Vitrinite Reflectance ◽  
Stable Carbon Isotope ◽  
Source Rocks ◽  
Crude Oils ◽  
Type I ◽  
Stable Carbon ◽  
Potential Source ◽  
Geochemical Parameters ◽  
Rock Eval

This search aims to apply developed geochemical methods to a number of oils and source rock extracts to better establish the features of ancient environments that occurred in the Murzuq basin. Geochemical and geophysical approaches were used to confirm further a source contribution from other Paleozoic formations to hydrocarbon accumulations in the basin. One hundred and forty rock units were collected from B1-NC151, D1-NC174, A1-NC 76, D1-NC 151, F1-NC58, A1-NC 186, P1-NC 101, D1-NC 58, H1-NC58 and A1-NC58 wells. Seven crude oils were collocated A1-NC186, B1-NC186, E2-NC101, F3-NC174, A10-NC115, B10-NC115 and H10-NC115 wells. A geochemical assessment of the studied rocks and oils was done by means of geochemical parameters of total organic carbon (TOC), Rock-Eval analysis, detailed-various biomarkers and stable carbon isotope. The TOC values from B1-NC151 range 0.40% to 8.5%, A1-NC186 0.3% and 1.45, A1-NC76 0.39% to 0.74%, D1-NC151 0.40% to 2.00% to F1-NC58 0.40% to 1.12%. D1_NC174 0.30% to 10 %, P1-NC101 0.80% to 1.35%, D1-NC58 0.5% to 1.10%, H1-NC58 0.20% to 3.50%, A1-NC58 0.40% to 1.60%. The categories of organic matter from rock-eval pyrolysis statistics point to that type II kerogen is the main type, in association with type III, and no of type I kerogen recognized. Vitrinite reflectance (%Ro), Tmax and Spore colour index (SCI) as thermal maturity parameters reflect that the measured rock units are have different maturation levels, ranging from immature to mature sources. acritarchs distribution for most samples could be recognized and Palynomorphs are uncommon. Pristane to phytane ratios (> 1) revealed marine shale to lacustrine of environmental deposition. The Stable carbon isotope ( δ 13 C) values of seven rock-extract samples are -30.98‰ and -29.14‰ of saturates and -29.86‰ to -28.37‰ aromatic fractions. The oil saturate hydrocarbon fractions range between -29.36‰ to -28.67‰ and aromatic are among -29.98 ‰ to -29.55 ‰. The δ 13 C data in both rock extractions and crude oils are closer to each other, typical in sign of Paleozoic age. It is clear that the base of Tanezzuft Formation (Hot shale) is considered the main source rocks. The Devonian Awaynat Wanin Formation as well locally holds sufficient oil prone kerogen to consider as potential source rocks. Ordovician Mamuniyat Formation shales may poorly contain oil prone kerogen to be addressed in future studies. An assessment of the correlations between the oils and potential source rocks and between the oils themselves indicated that most of the rocks extracts were broadly similar to most of the oils and supported by carbon stable isotope analysis results.

Shale gas resource assessment in the Merlinleigh Sub-basin, Carnarvon Basin

2015 ◽  
Vol 55 (2) ◽  
pp. 452
Author(s):  
Joanna Wong ◽  
Mohammad Bahar
Keyword(s):  
Shale Gas ◽  
Resource Assessment ◽  
Poor Quality ◽  
Organic Content ◽  
Source Rocks ◽  
Geochemical Data ◽  
Geochemical Parameters ◽  
The Monte Carlo Method ◽  
Petrophysical Logs ◽  
Carnarvon Basin

The recent shale gas developments in the US have encouraged exploration for shale gas resource in WA. In the largely unexplored Carnarvon Basin, the Merlinleigh Sub-basin is predominately of Permian strata and has been shown to contain high-quality gas-prone source rocks from geochemical data. Three main potential shale layers, the Gneudna Formation, Wooramel Group and the Byro Group, were identified based on the shale ranking parameters. Geochemical data was collected and analysed for the type of kerogen, total organic content (TOC), generation potential and thermal maturity. These parameters enabled a gas-in-place resource estimation to be made for each of the formations. The TOC data from various wells were validated by using petrophysical logs and the ΔlogR method. In comparison with the geochemical data, both values produced a good match, validating both sets of data. The three layers were ranked according to their geochemical parameters and any petrophysical or geomechanical characteristics. It was identified that the Wooramel Group contains the best quality source rocks, followed by the Byro Group. The Gneudna Formation was found to have poor quality source rocks. The Monte Carlo method by Crystal Ball was selected to estimate the probabilistic resources of these three layers. According to the P50 estimations, the Byro Group, Wooramel Group and the Gneudna Formation contained resources of 51.6 tcf, 40.1 tcf and 1.4 tcf, respectively.

Evaluation of Energy Storage Potential of Unconventional Shale Reservoirs Using Numerical Simulation of Cyclic Gas Injection

2021 ◽  
Vol 143 (11) ◽  
Author(s):  
Chad Augustine ◽  
Henry Johnston ◽  
David L. Young ◽  
Kaveh Amini ◽  
Ilkay Uzun ◽  
...  
Keyword(s):  
Energy Storage ◽  
Natural Gas ◽  
Shale Gas ◽  
Gas Injection ◽  
Compressed Air ◽  
Published Data ◽  
Storage Potential ◽  
Shale Reservoirs ◽  
Cyclic Injection

Abstract Compressed air energy storage (CAES) stores energy as compressed air in underground formations, typically salt dome caverns. When electricity demand grows, the compressed air is released through a turbine to produce electricity. CAES in the US is limited to one plant built in 1991, due in part to the inherent risk and uncertainty of developing subsurface storage reservoirs. As an alternative to CAES, we propose using some of the hundreds of thousands of hydraulically fractured horizontal wells to store energy as compressed natural gas in unconventional shale reservoirs. To store energy, produced or “sales” natural gas is injected back into the formation using excess electricity and is later produced through an expander to generate electricity. To evaluate this concept, we performed numerical simulations of cyclic natural gas injection into unconventional shale reservoirs using cmg-gem commercial reservoir modeling software. We tested short-term (diurnal) and long-term (seasonal) energy storage potential by modeling well injection and production gas flowrates as a function of bottom-hole pressure. First, we developed a conceptual model of a single fracture stage in an unconventional shale reservoir to characterize reservoir behavior during cyclic injection and production. Next, we modeled cyclic injection in the Marcellus shale gas play using published data. Results indicate that Marcellus unconventional shale reservoirs could support both short- and long-term energy storage at capacities of 100–1000 kWe per well. The results indicate that energy storage in unconventional shale gas wells may be feasible and warrants further investigation.

scholarly journals Pore Structures of the Lower Permian Taiyuan Shale and Limestone in the Ordos Basin and the Significance to Unconventional Natural Gas Generation and Storage

Geofluids ◽  
2022 ◽  
Vol 2022 ◽  
pp. 1-16
Author(s):  
L. Zhang ◽  
Q. Zhao ◽  
C. Wu ◽  
Z. Qiu ◽  
Q. Zhang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Natural Gas ◽  
Shale Gas ◽  
Pore Volume ◽  
Ordos Basin ◽  
Source Rocks ◽  
Taiyuan Formation ◽  
Oil Generation ◽  
Unconventional Natural Gas ◽  
The Ordos Basin

In the Ordos Basin, multiple sets of coal seams, organic-rich shale, and limestone are well developed in the Permian Taiyuan Formation, which are favorable targets for collaborative exploration of various types of unconventional natural gas resources, including coalbed methane, shale gas, and tight gas. In this study, core samples from the Permian Taiyuan Formation in the eastern margin of the Ordos Basin were used to carry out a series of testing and analysis, such as the organic matter characteristics, the mineral composition, and the pore development characteristics. In the shale of the Taiyuan Formation, the total organic carbon (TOC) content is relatively high, with an average of 5.38%. A thin layer of black shale is developed on the top of the Taiyuan Formation, which is relatively high in TOC content, with an average of 9.72%. The limestone in the Taiyuan Formation is also relatively high in organic matter abundance, with an average of 1.36%, reaching the lower limit of effective source rocks (>1%), being good source rocks. In the shale of the Taiyuan Formation, various types of pores are well developed, with relatively high overall pore volume and pore-specific surface area, averaging 0.028 ml/g and 13.28 m2/g, respectively. The pore types are mainly mineral intergranular pores and clay mineral interlayer fractures, while organic matter-hosted pores are poorly developed. The limestone of the Taiyuan Formation is relatively tight, with lower pore volume and pore-specific surface area than those of shale, averaging 0.0106 ml/g and 2.72 m2/g, respectively. There are mainly two types of pores, namely, organic matter-hosted pores and carbonate mineral dissolution pores, with a high surface pore rate. The organic matter in the limestone belongs to the oil-generation kerogen. During thermal evolution, the organic matter has gone through the oil-generation window, generating a large number of liquid hydrocarbons, which were cracked into a large number of gaseous hydrocarbons at the higher mature stage. As a result, a large number of organic matter-hosted pores were generated. The study results show that in the Ordos Basin, the shale and limestone of the Permian Taiyuan Formation have great potential in terms of unconventional natural gas resources, providing a good geological basis for the collaborative development of coal-bearing shale gas and tight limestone gas in the Taiyuan Formation.

Exploring and appraising the oldest gas accumulations in Australia

2013 ◽  
Vol 53 (2) ◽  
pp. 470
Author(s):  
Ray Johnson ◽  
Josh Bluett ◽  
Luke Titus ◽  
David Warner
Keyword(s):  
Shale Gas ◽  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Drill Cuttings ◽  
Exciting Potential ◽  
Air Drilling ◽  
Unconventional Oil And Gas ◽  
Shale Reservoirs ◽  
Middle Proterozoic

In early 2012, Armour Energy set out to evaluate the Middle-Proterozoic formations in the Batten Trough, McArthur Basin, NT. The Batten Trough holds a massive potential shale gas play in the Barney Creek Formation, and recent gas discoveries in the overlying Lynott and Reward formations, and underlying Coxco Dolomite. The Lawn Supersequence, Isa Superbasin, Queensland, is another Middle-Proterozoic shale gas play with overlying and underlying conventional and unconventional oil and gas accumulations. Exploratory drilling between the 1980s and 1990s showed gas and oil shows across the Isa Superbasin, Queensland. Egilabria–1, ATP 1087, exhibited 390 gas units while drilling with mud, highlighting the prospectivity of this area. In both areas, the Barney Creek and Lawn Hill formations are proven source rocks and are significantly older than North American shale reservoirs. In 2012, an innovative exploration program was designed and implemented in the NT to maximise the capture of drilling data while integrating data from previous mineral and petroleum exploration programs. This resulted in gas discoveries at Cow Lagoon–1, EP 176, and in the Glyde–1 and Glyde–1 ST lateral wells in the Glyde Sub-basin in EP171. In both cases, air drilling was instrumental in aiding drilling penetration rates, gauging gas influx while drilling, and allowing geologists to rapidly obtain and assess drill cuttings. The authors first discuss the details of the formation evaluation methods used in Armour’s successful 2012 program and how these methods are extended to Armour’s 2013 program in the Isa Superbasin, northern Queensland. Next, an outline of the strategy for further delineation of the Batten Trough is provided. Finally, the authors summarise the exciting potential of the Lawn Supersequence in Queensland.

scholarly journals Method for Analyzing the Molecular and Carbon Isotope Composition of Volatile Hydrocarbons (C1–C9) in Natural Gas

2018 ◽  
Vol 2018 ◽  
pp. 1-9
Author(s):  
Chunhui Cao ◽  
Zhongping Li ◽  
Liwu Li ◽  
Li Du
Keyword(s):  
Natural Gas ◽  
Carbon Isotope ◽  
Solid Phase ◽  
Isotope Composition ◽  
Carbon Number ◽  
Carbon Isotope Composition ◽  
Source Rocks ◽  
Light Hydrocarbons ◽  
Composition Data ◽  
Relative Standard

Solid-phase microextraction (SPME) coupled with gas chromatography-isotope ratio mass spectrometry (GC-IRMS) has already been applied to collect and identify volatile light hydrocarbons in oil and source rocks. However, this technology has not yet been used to analyze volatile light hydrocarbons in dry gas (natural gas with C1/C2+> 95%). In this study, we developed a method to measure the molecular and carbon isotope composition of natural gas using divinylbenzene/carboxen/polydimethylsiloxane (DVB/CAR/PDMS) fiber. This fiber proved to be suitable for extracting C1–C9hydrocarbons from natural gas without inducing carbon isotopic fractionation. Notably, the extraction coefficients of the analytes were not the same but rather increased with the increasing carbon number of the hydrocarbons. Nevertheless, we successfully identified 24 hydrocarbons from the in-lab standard natural gas, while also obtaining the carbon isotope composition of C1to C9hydrocarbons with satisfying repeatability. The relative standard deviation (RSD) of the molecular composition data was in the range of 0.06–0.74%, with the RSDs of the carbon isotope composition data not exceeding 1‰. Finally, seven natural gas samples, collected from different sedimentary basins, were successfully analyzed and the stable carbon isotope compositions of C1–C9hydrocarbons present in these were determined through this method. Overall, the new approach provides a simple but useful technique to obtain more geochemical information about the source and evolution of natural gas.

UNDERSTANDING SOURCE, DISTRIBUTION AND PRESERVATION OF AUSTRALIAN NATURAL GAS: A GEOCHEMICAL PERSPECTIVE

2001 ◽  
Vol 41 (1) ◽  
pp. 523 ◽  
Author(s):  
C.J. Boreham ◽  
J.M. Hope ◽  
B. Hartung-Kagi
Keyword(s):  
Organic Matter ◽  
Natural Gas ◽  
Isotopic Composition ◽  
Carbon Isotopic Composition ◽  
Source Rocks ◽  
Source Distribution ◽  
Hydrocarbon Gases ◽  
Carbon Isotopic ◽  
Wet Gas ◽  
Gaseous Hydrocarbons

Natural gases from all of Australia’s major gas provinces in the Adavale, Amadeus, Bass, Bonaparte, Bowen/ Surat, Browse, Canning, Carnarvon, Cooper/Eromanga, Duntroon, Gippsland, Otway and Perth basins have been examined using molecular and carbon isotopic compositions in order to define their source, maturity and secondary alteration processes.The molecular compositions of the gaseous hydrocarbons range from highly wet to extremely dry. On average, reservoired gases predominantly derived from land plants are slightly wetter than those derived from marine sources. The non-hydrocarbon gases CO2 and N2 were sourced from both inorganic and organic materials. A mantle and/or igneous origin is likely in the majority of gases with CO2 contents >5%. For gases with lower CO2 contents, an additional organic input, associated with hydrocarbon generation, is recognised where δ13C CO2 is A strong inter-dependency between source and maturity has been recognised from the carbon isotopic composition of individual gaseous hydrocarbons. This relationship has highlighted some shortcomings of common graphical tools for interpretation of carbon isotopic data. The combination of the carbon isotopic composition of gaseous hydrocarbons and the low molecular weight nalkanes in the accompanying oil allows our knowledge of oil-source correlations and oil families to be used to correlate gases with their sources. This approach has identified source rocks for gas ranging in age from the Ordovician in the Amadeus Basin to Late Cretaceous- Early Tertiary sources in the Bass and Gippsland basins. The carbon isotopic composition of organic matter, approximated using the δ13C of iso-butane, shows a progressive enrichment in 13C with decreasing source age, together with marine source rocks for gas being isotopically lighter than those from land plant sources. The Permian was a time when organic matter was enriched in 13C and isotopically uniform on a regional scale.Secondary, in-reservoir alteration has played a major role in the modification of Australian gas accumulations. Thus, biodegradation, prominent in the Bowen/Surat, Browse, Carnarvon and Gippsland basins, is found in both hydrocarbon and non-hydrocarbon gases. This is recognised by an increase in gas dryness, elevated isoalkane to n-alkane ratio, differential increase in δ13C of the individual wet gas components, a decrease in δ13C of methane and a reduction in CO2 content concomitant with enrichment in 13C. Evidence of water-washing has been identified in accumulations in the Bonaparte and Cooper/Eromanga basins, resulting in an increase in the wet gas content. Seal integrity is also a major risk for the preservation of natural gas accumulations, although its effect on gas composition is only evident in extreme cases, such as the Amadeus Basin, where preferential leakage of methane in the Palm Valley field has resulted in the residual methane becoming enriched in 13C.The greater mobility of gas within subsurface rocks can have a detrimental effect on oil composition whereby gas-stripping of light hydrocarbons is common amongst Australian oil accumulations. Alternatively, the availability of gas, derived from a source rock common to or different from oil, was likely to have been a prime factor controlling the regional distribution of oil, whereby mixing of both results in increased oil mobility and can lead to a greater access to the number and types of traps in the subsurface.

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