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Geosciences
Special Issues
Natural Gas Origin, Migration, Alteration and Seepage
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Natural Gas Origin, Migration, Alteration and Seepage

A special issue of Geosciences (ISSN 2076-3263). This special issue belongs to the section "Geochemistry".

Deadline for manuscript submissions: closed (28 February 2017) | Viewed by 42914

Special Issue Editors

Prof. Dr. Alexei V. Milkov

E-Mail Website
Guest Editor
Department of Geology and Geological Engineering, Colorado School of Mines, 1500 Illinois St., Golden, CO 80401, USA
Interests: petroleum geoscience; petroleum geochemistry; basin modelling; methane emissions; mud volcanoes; gas hydrates
Dr. Giuseppe Etiope

E-Mail Website
Guest Editor
Istituto Nazionale di Geofisica e Vulcanologia, Sezione Roma 2, Italy
Interests: natural gas geochemistry; hydrocarbon seepage; biotic and abiotic methane origin

Special Issue Information

Dear Colleagues,

The main objective of this Special Issue of Geosciences is to communicate new research findings on natural gas. The amount of molecular and isotopic data on natural gases is rapidly increasing as oil and gas companies now routinely collect and analyse gas samples while exploring and developing conventional and unconventional resources. Researchers also generate large amounts of gas data by sampling gas seeps, recovering gas hydrates and conducting pyrolysis experiments in the labs. Interpretation of this data and its integration with geology and basin modelling can provide key new insights on the origin, migration, alteration and seepage of natural gas.

This Special Issue will provide an outlet for rapid, widely accessible publication of peer-reviewed studies by researchers from both the petroleum industry and academia around the world. We welcome research on organic and inorganic origin of natural gas, kinetics of gas generation, migration of gas through sedimentary cover, accumulation of gas in natural pools, association between oil and gas, alteration of gas in the upper part of sedimentary cover and gas/oil seepage (including mud volcanoes and microseepage).

Prof. Dr. Alexei V. Milkov
Dr. Giuseppe Etiope
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Geosciences is an international peer-reviewed open access monthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 1800 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • natural gas
  • hydrocarbons
  • methane
  • gas migration
  • oil and gas fields
  • biodegradation
  • seeps
  • mud volcanoes
  • microseepage

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Published Papers (6 papers)

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Research

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9041 KiB  
Article
Stable Isotope Systematics of Coalbed Gas during Desorption and Production
by Martin Niemann and Michael J. Whiticar
Geosciences 2017, 7(2), 43; https://doi.org/10.3390/geosciences7020043 - 14 Jun 2017
Cited by 30 | Viewed by 7064
Abstract
The stable carbon isotope ratios of coalbed methane (CBM) demonstrate diagnostic changes that systematically vary with production and desorption times. These shifts can provide decisive, predictive information on the behaviour and potential performance of CBM operations. Samples from producing CBM wells show a [...] Read more.
The stable carbon isotope ratios of coalbed methane (CBM) demonstrate diagnostic changes that systematically vary with production and desorption times. These shifts can provide decisive, predictive information on the behaviour and potential performance of CBM operations. Samples from producing CBM wells show a general depletion in 13C-methane with increasing production times and corresponding shifts in δ13C-CH4 up to 35.8‰. Samples from canister desorption experiments show mostly enrichment in 13C for methane with increasing desorption time and isotope shifts of up to 43.4‰. Also, 13C-depletion was observed in some samples with isotope shifts of up to 32.1‰. Overall, the magnitudes of the observed isotope shifts vary considerably between different sample sets, but also within samples from the same source. The δ13C-CH4 values do not have the anticipated signature of methane generated from coal. This indicates that secondary processes, including desorption and diffusion, can influence the values. It is also challenging to deconvolute these various secondary processes because their molecular and isotope effects can have similar directions and/or magnitudes. In some instances, significant alteration of CBM gases has to be considered as a combination of secondary alteration effects. Full article
(This article belongs to the Special Issue Natural Gas Origin, Migration, Alteration and Seepage)
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26088 KiB  
Article
Inventory of Onshore Hydrocarbon Seeps in Romania (HYSED-RO Database)
by Artur Ionescu, Pierfrancesco Burrato, Calin Baciu, Giuseppe Etiope and Boglarka-Mercedesz Kis
Geosciences 2017, 7(2), 39; https://doi.org/10.3390/geosciences7020039 - 01 Jun 2017
Cited by 4 | Viewed by 7981
Abstract
Seeps are the expression of the migration of hydrocarbons from subsurface accumulations to the surface in sedimentary basins. They may represent an important indication of the presence of petroleum (gas and oil) reservoirs and faults, and are a natural source of greenhouse gas [...] Read more.
Seeps are the expression of the migration of hydrocarbons from subsurface accumulations to the surface in sedimentary basins. They may represent an important indication of the presence of petroleum (gas and oil) reservoirs and faults, and are a natural source of greenhouse gas (methane) and atmospheric pollutants (ethane, propane) to the atmosphere. Romania is one of the countries with the largest number of seeps in the world, due to the high petroleum potential and active tectonics. Based on a review of the available literature, and on the field surveys performed by the authors during the last 17 years, we report the first comprehensive GIS-based inventory of 470 seeps in Romania (HYSED-RO), including gas seeps (10.4% of the total), oil seeps (11.7%), mud volcanoes (50.4%), gas-rich springs (12.6%), asphalt (solid) seeps (4.3%), unclassified manifestations (4.0%), and uncertain seeps (6.6%). Seeps are typically located in correspondence with major faults and vertical and fractured stratigraphic contacts associated to petroleum reservoirs (anticlines) in low heat flow areas, and their gas-geochemistry reflects that of the subsurface reservoirs. The largest and most active seeps occur in the Carpathian Foredeep, where they release thermogenic gas, and subordinately in the Transylvanian Basin, where gas is mainly microbial. HYSED-RO may represent a key reference for baseline characterization prior to subsurface petroleum extraction, for environmental studies, and atmospheric greenhouse gas emission estimates in Romania. Full article
(This article belongs to the Special Issue Natural Gas Origin, Migration, Alteration and Seepage)
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1925 KiB  
Article
Geochemistry of Petroleum Gases and Liquids from the Inhassoro, Pande and Temane Fields Onshore Mozambique
by Markus J. Loegering and Alexei V. Milkov
Geosciences 2017, 7(2), 33; https://doi.org/10.3390/geosciences7020033 - 05 May 2017
Cited by 14 | Viewed by 7750
Abstract
Although the first petroleum fields in the Mozambique basin were discovered more than 60 years ago, the composition and origin of petroleum fluids in this basin are largely unknown. We studied the geochemical composition of petroleum gases and liquids from the Inhassoro, Pande [...] Read more.
Although the first petroleum fields in the Mozambique basin were discovered more than 60 years ago, the composition and origin of petroleum fluids in this basin are largely unknown. We studied the geochemical composition of petroleum gases and liquids from the Inhassoro, Pande and Temane fields located onshore Mozambique. The gases are relatively dry (methane-dominated, average C1/(C1–C5) ratio is ~0.96), have pure thermogenic origin, originate predominantly from marine shale source organofacies and show no evidence of primary microbial gas or biodegradation. Most condensates have relatively high API gravity up to 76 degrees, are very mature and contain only traces of biomarkers, likely from migration contamination. However, biomarkers in the light oil from the Inhassoro field indicate that the oil derived from sub-oxic marine shales of the Late Cretaceous age. We suggest that the Aptian-Coniacian Domo Shale is the likely source rock for petroleum gases and liquids in the studied fields. Our geochemical data, including gas isotopes, as well as source-specific and age-specific biomarkers, exclude coals in the Late Carboniferous—Early Jurassic Karoo Supergroup as effective source rocks for the studied fields. Full article
(This article belongs to the Special Issue Natural Gas Origin, Migration, Alteration and Seepage)
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16995 KiB  
Article
Role of Faults in Hydrocarbon Leakage in the Hammerfest Basin, SW Barents Sea: Insights from Seismic Data and Numerical Modelling
by Ilya Ostanin, Zahie Anka and Rolando Di Primio
Geosciences 2017, 7(2), 28; https://doi.org/10.3390/geosciences7020028 - 15 Apr 2017
Cited by 22 | Viewed by 9349
Abstract
Hydrocarbon prospectivity in the Greater Barents Sea remains enigmatic as gas discoveries have dominated over oil in the past three decades. Numerous hydrocarbon-related fluid flow anomalies in the area indicate leakage and redistribution of petroleum in the subsurface. Many questions remain unanswered regarding [...] Read more.
Hydrocarbon prospectivity in the Greater Barents Sea remains enigmatic as gas discoveries have dominated over oil in the past three decades. Numerous hydrocarbon-related fluid flow anomalies in the area indicate leakage and redistribution of petroleum in the subsurface. Many questions remain unanswered regarding the geological driving factors for leakage from the reservoirs and the response of deep petroleum reservoirs to the Cenozoic exhumation and the Pliocene-Pleistocene glaciations. Based on 2D and 3D seismic data interpretation, we constructed a basin-scale regional 3D petroleum systems model for the Hammerfest Basin (1 km × 1 km grid spacing). A higher resolution model (200 m × 200 m grid spacing) for the Snøhvit and Albatross fields was then nested in the regional model to further our understanding of the subsurface development over geological time. We tested the sensitivity of the modeled petroleum leakage by including and varying fault properties as a function of burial and erosion, namely fault capillary entry pressures and permeability during glacial cycles. In this study, we find that the greatest mass lost from the Jurassic reservoirs occurs during ice unloading, which accounts for a 60%–80% reduction of initial accumulated mass in the reservoirs. Subsequent leakage events show a stepwise decrease of 7%–25% of the remaining mass from the reservoirs. The latest episode of hydrocarbon leakage occurred following the Last Glacial Maximum (LGM) when differential loading of Quaternary strata resulted in reservoir tilt and spill. The first modeled hydrocarbon leakage event coincides with a major fluid venting episode at the time of a major Upper Regional angular Unconformity (URU, ~0.8 Ma), evidenced by an abundance of pockmarks at this stratigraphic interval. Our modelling results show that leakage along the faults bounding the reservoir is the dominant mechanism for hydrocarbon leakage and is in agreement with observed shallow gas leakage indicators of gas chimneys, pockmarks and fluid escape pipes. We propose a conceptual model where leaked thermogenic gases from the reservoir were also locked in gas hydrate deposits beneath the base of the glacier during glaciations of the Hammerfest Basin and decomposed rapidly during subsequent deglaciation, forming pockmarks and fluid escape pipes. This is the first study to our knowledge to integrate petroleum systems modelling with seismic mapping of hydrocarbon leakage indicators for a holistic numerical model of the subsurface geology, thus closing the gap between the seismic mapping of fluid flow events and the geological history of the area. Full article
(This article belongs to the Special Issue Natural Gas Origin, Migration, Alteration and Seepage)
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6954 KiB  
Article
Characteristics of Microbial Coalbed Gas during Production; Example from Pennsylvanian Coals in Indiana, USA
by Maria Mastalerz, Agnieszka Drobniak and Arndt Schimmelmann
Geosciences 2017, 7(2), 26; https://doi.org/10.3390/geosciences7020026 - 13 Apr 2017
Cited by 6 | Viewed by 4110
Abstract
Coalbed gases from 11 wells producing from the Springfield and Seelyville Coal Members (Pennsylvanian) were analyzed for composition and carbon and hydrogen stable isotope ratios in four sampling events to investigate short-term variation trends. Nine wells in the Seelyville Coal Member produce coalbed [...] Read more.
Coalbed gases from 11 wells producing from the Springfield and Seelyville Coal Members (Pennsylvanian) were analyzed for composition and carbon and hydrogen stable isotope ratios in four sampling events to investigate short-term variation trends. Nine wells in the Seelyville Coal Member produce coalbed gases from the virgin seam, whereas two wells in the Springfield Coal Member produce gas from mine voids. Methane dominates gas composition in all wells, and its content ranges from ~94% to almost 98%, with ethane typically accounting for less than 0.01%. Carbon dioxide content in most samples is below 1%, whereas N2 content ranges from less than 2% to 4.8%. Methane δ13C values range from −55.3‰ to −61.1‰, and δ2H values range from −201‰ to −219‰. Isotopic values of methane and C1/(C2 + C3) ratios indicate a biogenic origin along the CO2-reduction pathway, consistent with previous studies in this area. Our results demonstrate that gas properties may change significantly during a period of one year of production history. Compositional trends (e.g., C1/(C2 + C3), CH4/CO2 ratios) are specific for each well and often irregular. These changes result from a combined influence of numerous factors and, therefore, are difficult to predict. Full article
(This article belongs to the Special Issue Natural Gas Origin, Migration, Alteration and Seepage)
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Review

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3867 KiB  
Review
Evaluation of Near-Surface Gases in Marine Sediments to Assess Subsurface Petroleum Gas Generation and Entrapment
by Michael A. Abrams
Geosciences 2017, 7(2), 35; https://doi.org/10.3390/geosciences7020035 - 04 May 2017
Cited by 35 | Viewed by 5657
Abstract
Gases contained within near-surface marine sediments can be derived from multiple sources: shallow microbial activity, thermal cracking of organic matter and inorganic materials, or magmatic-mantle degassing. Each origin will display a distinctive hydrocarbon and non-hydrocarbon composition as well as compound-specific isotope signature and [...] Read more.
Gases contained within near-surface marine sediments can be derived from multiple sources: shallow microbial activity, thermal cracking of organic matter and inorganic materials, or magmatic-mantle degassing. Each origin will display a distinctive hydrocarbon and non-hydrocarbon composition as well as compound-specific isotope signature and thus the interpretation of origin should be relatively straightforward. Unfortunately, this is not always the case due to in situ microbial alteration, non-equilibrium phase partitioning, mixing, and fractionation related to the gas extraction method. Sediment gases can reside in the interstitial spaces, bound to mineral or organic surfaces and/or entrapped in carbonate inclusions. The interstitial sediment gases are contained within the sediment pore space, either dissolved in the pore waters (solute) or as free (vapour) gas. The bound gases are believed to be attached to organic and/or mineral surfaces, entrapped in structured water or entrapped in authigenic carbonate inclusions. The purpose of this paper is to provide a review of the gas types found within shallow marine sediments and examine issues related to gas sampling and extraction. In addition, the paper will discuss how to recognise mixing, alteration and fractionation issues to best interpret the seabed geochemical results and determine gas origin to assess subsurface petroleum gas generation and entrapment. Full article
(This article belongs to the Special Issue Natural Gas Origin, Migration, Alteration and Seepage)
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