Browsing by Author "Becker, Veith"
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- ItemOpen AccessMolecular and stable carbon isotope geochemistry of mud-gas-derived hydrocarbons and its application for the assessment of low-permeability reservoirs from the Montney Formation, Western Canada(Elsevier, 2022-01-03) Cesar, Jaime; Mayer, Bernhard; Becker, Veith; Nightingale, Michael; Ardakani, Omid H.Mud-gas isotope logging (MGIL) of hydrocarbons (methane, ethane, propane) has become a widely used approach to fingerprint gas-bearing formations during the drilling of vertical and horizontal oil and gas wells often with the goal to assess potential cross-formational gas migration. In this study, we have used mud-gas molecular and isotope data to assess the usefulness of MGIL for the geochemical assessment of a single low-permeability reservoir formation, the Montney Formation in Western Canada. An example from a well completed in British Columbia shows that hydrocarbon samples collected in IsoJars® tend towards more positive carbon isotope ratios compared to data for samples obtained using IsoTubes®, potentially attributed to 13C enriched residual gas retained in the cuttings. Additionally, in publically available mud-gas data from 45 other wells, it was found that the carbon isotope ratios of mud-gas from the Montney Formation are overall consistent with the thermal maturity of this stratigraphic unit, but the data display a relatively scattered trend on a thermal maturity plot based on Δ13CC1-C2 and Δ13CC1-C3. Molecular parameters such as [C1/(C2 + C3)] can be modified via processes such as desorption and diffusion after sampling gases in IsoJars®, while the i-C4/n-C4 ratio was found to be the most consistent molecular parameter between sampling techniques. We conclude that mud-gas molecular and isotope data derived from samples collected in IsoTubes® are suitable for geochemical assessment (e.g. thermal maturity, fluid–fluid correlations) of low permeability hydrocarbon reservoirs such as the Montney Formation.
- ItemOpen AccessOrganic and isotope geochemistry analysis of petroleum condensates from the unconventional portion of the Montney Formation, Western Canada(Elsevier, 2020-08) Cesar, Jaime; Becker, Veith; Mayer, BernhardThe Montney Formation is a rather complex petroleum reservoir because it contains in-situ and migrated hydrocarbons. Previous organic geochemistry studies reported for this play were based on biomarker ratios of petroleum fluids from the conventional part of this reservoir. Furthermore, there is no isotope study on liquid hydrocarbons from this formation reported to this date. Therefore, we determined the organic and isotope geochemistry of condensate petroleum from the unconventional portion of the Montney Formation to fill this knowledge gap. The condensates were found to be normal fluids of increasing thermal maturity with increasing depth and from the northeast to the southwest. Light hydrocarbon parameters such as paraffinicity (n-C7/methylcyclohexane) and aromaticity (toluene/n-C7) showed to be governed by thermal maturity according to the known maturity trends (increasing depth, and northeast to southwest). The molecular fingerprint of the condensates is to some extent bimodal (noticeable at n-C13) suggesting the possibility of two hydrocarbon charges in the reservoir. This is further evidenced by the stable carbon isotope profile of n-alkanes where light hydrocarbons (C8-C13) show a normal distribution (decreasing δ13C with carbon number) whereas heavier compounds (C19+) show a reverse trend (increasing δ13C with carbon number). We suggest that condensate petroleum produced in the study area corresponds to a mixture of hydrocarbons sourced by the Montney Formation plus alteration products from a pre-existing oil charge that migrated into Montney reservoirs before further burial and thermal maturation of this rock. Producing intervals were distinguished using the δ13C values of n-C11, n-C12, n-C22, and n-C23.
- ItemOpen AccessRedox controls on methane formation, migration and fate in shallow aquifers(Copernicus Publications, 2016-07-12) Humez, Pauline; Mayer, Bernhard; Nightingale, Michael; Becker, Veith; Kingston, Andrew; Taylor, Stephen; Bayegnak, Guy; Millot, Romain; Kloppmann, WolframDevelopment of unconventional energy resources such as shale gas and coalbed methane has generated some public concern with regard to the protection of groundwater and surface water resources from leakage of stray gas from the deep subsurface. In terms of environmental impact to and risk assessment of shallow groundwater resources, the ultimate challenge is to distinguish (a) natural in situ production of biogenic methane, (b) biogenic or thermogenic methane migration into shallow aquifers due to natural causes, and (c) thermogenic methane migration from deep sources due to human activities associated with the exploitation of conventional or unconventional oil and gas resources. This study combines aqueous and gas (dissolved and free) geochemical and isotope data from 372 groundwater samples obtained from 186 monitoring wells of the provincial Groundwater Observation Well Network (GOWN) in Alberta (Canada), a province with a long record of conventional and unconventional hydrocarbon exploration. We investigated whether methane occurring in shallow groundwater formed in situ, or whether it migrated into the shallow aquifers from elsewhere in the stratigraphic column. It was found that methane is ubiquitous in groundwater in Alberta and is predominantly of biogenic origin. The highest concentrations of biogenic methane (> 0.01 mM or > 0.2 mgL−1), characterized by δ13CCH4 values < −55 ‰, occurred in anoxic Na-Cl, Na-HCO3, and Na-HCO3-Cl type groundwaters with negligible concentrations of nitrate and sulfate suggesting that methane was formed in situ under methanogenic conditions for 39.1 % of the samples. In only a few cases (3.7 %) was methane of biogenic origin found in more oxidizing shallow aquifer portions suggesting limited upward migration from deeper methanogenic aquifers. Of the samples, 14.1 % contained methane with δ13CCH4 values > −54 ‰, potentially suggesting a thermogenic origin, but aqueous and isotope geochemistry data revealed that the elevated δ13CCH4 values were caused by microbial oxidation of biogenic methane or post-sampling degradation of low CH4 content samples rather than migration of deep thermogenic gas. A significant number of samples (39.2 %) contained methane with predominantly biogenic C isotope ratios (δ13CCH4 < −55 ‰) accompanied by elevated concentrations of ethane and sometimes trace concentrations of propane. These gases, observed in 28.1 % of the samples, bearing both biogenic (δ13C) and thermogenic (presence of C3) characteristics, are most likely derived from shallow coal seams that are prevalent in the Cretaceous Horseshoe Canyon and neighboring formations in which some of the groundwater wells are completed. The remaining 3.7 % of samples were not assigned because of conflicting parameters in the data sets or between replicates samples. Hence, despite quite variable gas concentrations and a wide range of δ13CCH4 values in baseline groundwater samples, we found no conclusive evidence for deep thermogenic gas migration into shallow aquifers either naturally or via anthropogenically induced pathways in this baseline groundwater survey. This study shows that the combined interpretation of aqueous geochemistry data in concert with chemical and isotopic compositions of dissolved and/or free gas can yield unprecedented insights into formation and potential migration of methane in shallow groundwater. This enables the assessment of cross-formational methane migration and provides an understanding of alkane gas sources and pathways necessary for a stringent baseline definition in the context of current and future unconventional hydrocarbon exploration and exploitation.
- ItemOpen AccessStable carbon isotope systematics of methane, ethane and propane from low-permeability hydrocarbon reservoirs(Elsevier, 2020-10-10) Cesar, Jaime; Nightingale, Michael; Becker, Veith; Mayer, BernhardWe have reassessed the stable carbon isotope systematics of methane (C1), ethane (C2), and propane (C3) in more than 500 natural gas samples from low-permeability hydrocarbon reservoirs around the world, with the purpose of providing new tools for thermal maturity assessment of natural gas that is increasingly produced from such reservoir types world-wide. A low-permeability reservoir resembles a semi-closed system and we found that the stable carbon isotope distribution in C1-C3 alkanes differs partially from what has been previously observed in natural gas from conventional hydrocarbon accumulations (e.g. C isotope distributions dominated by Rayleigh distillation and kinetic isotope effects). In a low-permeability reservoir, isotope exchange may play a more prominant role in the carbon isotope distribution, driving the system towards an even isotopic distribution (EID) of 6‰ between methane and ethane, and ethane and propane, at Ro of 1.5%. At higher maturity, ethane and propane depleted in 13C are formed as a consequence of thermal cracking of wet-gas components and possibly free radical decomposition/polymerization reactions, which leads to the occurrence of isotope reversals (δ13CC2 < δ13CC1 < δ13CC3, δ13CC2 < δ13CC3 < δ13CC1 and δ13CC3 < δ13CC2 < δ13CC1) at thermal maturity higher than 2.0%Ro. The diagram of the isotopic differences ∆13CC1-C2 (δ13CC1-δ13CC2) versus ∆13CC1-C3 (δ13CC1-δ13CC3) provides a new tool for classification of natural gas from low-permeability hydrocarbon reservoirs according to thermal history in three main regions: normal trend (subdivided into immature, oil/wet-gas window, and dry gas window), ethane reversal, and propane reversal with respect to methane. This new tool can be used to assess the maturity of the petroleum fluids and can assist in identifying hydrocarbon mixing.