Light Hydrocarbon Geochemistry of Oils in the Alpine Foreland Basin: Impact of Geothermal Fluids on the Petroleum System

Pytlak, Ł.; Leis, Albrecht; Prochaska, Walter; Sachsenhofer, Reinhard F.; Groß, Doris; Linzer, Hans‐Gert

doi:10.1155/2017/7182959

“…7), while minor deposits are found in Jurassic clastic rocks and algal limestones of the Upper Eocene. Main thermogenic hydrocarbon source rocks are also associated with deep marine Lower Oligocene pelitic rocks (Pytlak Ł et al 2017;Sachsenhofer and Schulz 2006;Sachsenhofer et al 2010). Although, the Malm aquifer is generally considered separated from aquifers of overlying stratigraphic units (Huber 1999), other studies suggested hydraulic connections between the Malm aquifer and oil-bearing rocks (Andrews et al 1987;Goldbrunner 2000;Gross et al 2015).…”

Section: Geothermal Fluids In the Molasse Basinmentioning

confidence: 99%

Dissolved organic compounds in geothermal fluids used for energy production: a review

Leins

¹

,

Bregnard²,

et al. 2022

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Dissolved organic matter (DOM) can be found in a variety of deep subsurface environments such as sedimentary basins, oil fields and mines. However, the origin, composition and fate of DOM within deep geothermal reservoirs used for energy production is relatively unknown. With well depths reaching a few kilometers, these sites give access to investigate deep subsurface environments. Natural DOM as well as artificial DOM (e.g., from chemical scaling inhibitors) might serve as nutrients for microorganisms or affect chemical properties of the fluids by complexation. Its composition might reveal hydraulic connections to organic-rich strata, giving insights to the fluid flow within the reservoir. This review presents an overview of a total of 143 fluid samples from 22 geothermal sites (mainly central Europe), from the literature and compiling data to address the importance of DOM in geothermal fluids and how it might affect geothermal operation. The environmental conditions of the sites included varied greatly. Temperatures range from 34 to $$200\,^{\circ }\hbox {C}$$ 200 ∘ C , depths from 850 to 5000 m, chloride content from 0.1 to $$160\,{\hbox {g}\,\hbox {L}^{-1}}$$ 160 g L - 1 , and dissolved organic carbon (DOC) concentrations from 0.1 to $$30.1\,{\hbox {g}\,\hbox {L}^{-1}}$$ 30.1 g L - 1 . The DOC concentrations were found to be generally lower in the fluids with temperatures below $$80\,{}^{\circ }\hbox {C}$$ 80 ∘ C . DOC concentrations were higher in fluids with temperatures above $$80\,{}^{\circ }\hbox {C}$$ 80 ∘ C and showed a decrease towards $$200\,{}^{\circ }\hbox {C}$$ 200 ∘ C . Microbial degradation might be the main driver for low DOC concentrations in the lower temperature range (below $$80\,{}^{\circ }\hbox {C}$$ 80 ∘ C ), while thermal degradation likely accounts for the decline in DOC in the temperature region between $$80\,{}^{\circ }\hbox {C}$$ 80 ∘ C and $$200\,{}^{\circ }\hbox {C}$$ 200 ∘ C . This review shows that DOM can be found in a variety of geothermal reservoirs and that it could be an additional essential tool to better understand fluid chemistry and reservoir conditions, and to optimize geothermal operation.

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“…Water-washing is the removal of light hydrocarbons with a relatively high solubility (e.g. benzene, toluene) via selective dissolution in a connected active aquifer (Elliott, 2015), and this process has recently been recognized in the North Alpine Foreland Basin (Pytlak et al, 2017c;Fig. 11).…”

Section: Hydrocarbon Alterationmentioning

confidence: 99%

Petroleum Systems in the Austrian Sector of the North Alpine Foreland Basin: An Overview

Groß

¹

,

Sachsenhofer

²

,

Bechtel

³

et al. 2018

Journal of Petroleum Geology

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Two separate petroleum systems have been identified in the Austrian sector of the North Alpine Foreland Basin: a lower Oligocene – Cenomanian/Eocene oil and thermogenic gas system; and an Oligocene‐Miocene microbial gas system. Recent studies by both academic and industry‐based research groups have resulted in an improved understanding of these petroleum systems, which are reviewed in this paper. Lower Oligocene organic‐rich intervals (up to 12 %TOC; HI: 400–600 mgHC/gTOC), capable of generating slightly more than 1 t of hydrocarbons/m2, are the source rocks for the thermogenic petroleum system in the Austrian sector of the North Alpine Foreland Basin. The present‐day distribution of this source rock is controlled by submarine mass movements which removed a large part of the organic‐rich interval from its depositional location during the late early Oligocene. The transported material was redeposited in locations to the south which are at the present day buried beneath Alpine thrust sheets. In addition, source rock units were incorporated into Molasse imbricates during Alpine deformation. Hydrocarbon generation began during the Miocene, and the oil kitchen was located to the south of the Alpine thrust front. Hence, lateral migration over distances of up to 50 km was required to charge the mainly Eocene and Cenomanian non‐ and shallow‐marine sandstone reservoir units. Hydrocarbons are in general trapped in structures related to east‐west trending normal faults, and differences in source rock facies resulted in the development of separate western and eastern oil families. Surprisingly, with the exception of some fields in the eastern part of the study area, associated gas contains varying (and sometimes very high) percentages of primary and secondary microbial methane. The composition of oil in some fields is influenced by both biodegradation and water washing. Post‐Miocene uplift in the Austrian sector of the basin had further effects on biodegradation and the consequent formation of secondary microbial gas, and also resulted in re‐migration. The upper Oligocene to lower Miocene succession (Puchkirchen Group, Hall Formation) provides both source and reservoir rocks for the microbial petroleum system in the Austrian sector of the North Alpine Foreland Basin. TOC contents (<1.0 %) and HI values (<140 mgHC/gTOC) of pelitic source rocks are typically low. Microbial gas was generated shortly after deposition during early diagenesis and was subsequently fixed in gas hydrates. Basin subsidence and high sedimentation rates resulted in decomposition of the hydrates below their stability zone, and reservoirs were filled during the early Miocene. Subsequent mixing of microbial gas with thermogenic gas and condensates is widespread. However, biodegradation has prevented precise determination of the fraction of thermogenic hydrocarbons present in gas samples. Reservoir sandstones were deposited within a deep‐marine channel belt along the axis of the North Alpine Foreland Basin, and reservoir quality depends on the precise posit...

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“…Heavy oil and solid bitumen in hydrocarbon reservoirs create barriers to fluid flow, causing porosity and permeability deterioration and, thus, serious production problems [1]. Undersaturated meteoric waters preferentially remove water-soluble compounds from oil, such as light aromatics (benzene and toluene) [2], which results in an increase of bitumen and heavy oil residues [3,4]. This process is known as water washing [5].…”

Section: Introductionmentioning

confidence: 99%

Meteoric Water Incursion, Crude Oil Degradation and Calcite Cementation of an Upper Cretaceous Reservoir in the Zagros Foreland Basin (Kurdistan Region of Iraq)

Mansurbeg

¹

,

Mohialdeen

²

,

Al-Juboury

³

et al. 2023

Water

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Field observations, together with the results of gas chromatography–mass spectrometry (GC-MS) and stable carbon isotope analysis of bitumen, coupled with fluid inclusion microthermometry and stable isotope analyses of closely associated vug- and fracture-filling columnar calcite in the Upper Cretaceous Bekhme Formation, Kurdistan Region of Iraq, suggest that the degradation of crude oil was caused by the regional incursion of meteoric waters. This incursion, which is interpreted to have occurred during tectonic uplift during the Zagros Orogeny, is evidenced by: (i) the depletion of n-alkanes and acyclic isoprenoid alkanes (pristane and phytane) in the bitumen; (ii) low δ13CVPDB values (−8.5‰ to −3.9‰) and δ18OVPDB values (−22.9‰ to −15.0‰), with more radiogenic Sr isotopic ratios (0.70771–0.70772) compared to Cretaceous seawater; and (iii) low salinity and low temperatures (20 to 40 °C) in fluid inclusions of the columnar calcite. This study demonstrates that regional meteoric water incursion into sedimentary basins can be linked to crude oil degradation accompanied by calcite cementation events in carbonate reservoirs.

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Light Hydrocarbon Geochemistry of Oils in the Alpine Foreland Basin: Impact of Geothermal Fluids on the Petroleum System

Cited by 4 publications

References 30 publications

Dissolved organic compounds in geothermal fluids used for energy production: a review

Dissolved organic compounds in geothermal fluids used for energy production: a review

Petroleum Systems in the Austrian Sector of the North Alpine Foreland Basin: An Overview

Meteoric Water Incursion, Crude Oil Degradation and Calcite Cementation of an Upper Cretaceous Reservoir in the Zagros Foreland Basin (Kurdistan Region of Iraq)

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