Revisiting the Hubbert–Rubey pore pressure model for overthrust faulting: Inferences from bedding-parallel detachment surfaces within Middle Devonian gas shale, the Appalachian Basin, USA

Aydin, Murat G.; Engelder, Terry

doi:10.1016/j.jsg.2014.07.010

Cited by 25 publications

(10 citation statements)

References 86 publications

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“…Figure 2. Stratigraphic section of the Appalachian basin, compiled from Osborn and McIntosh (2010), Osborn et al (2012), Wang and Carr (2013), Engelder (2014), andWilkins et al (2014). Veizer et al (1999).…”

Section: Discussionmentioning

confidence: 99%

Fluid evolution in fracturing black shales, Appalachian Basin

Hooker¹,

Cartwright²,

Stephenson³

et al. 2017

Bulletin

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Opening-mode veins in cores drilled from the mudrocks over-and underlying the major Silurian salt décollement in the Appalachian plateau (Tioga and Lawrence Counties, Pennsylvania), have mineralogic and isotopic compositions generally matching those of their host mudrocks, suggesting opening and filling amid little cross-stratal fluid motion. Calcite and most trace minerals probably entered the veins via dissolution-reprecipitation from nearby host rock. Consistent with this interpretation are the observations that (i) trace minerals within the veins, including quartz, pyrite, and dolomite, are invariably also present within the layers hosting the veins, with vein cement minerals generally reflecting the abundance and solubility of minerals in the host-rock, and (ii) carbon and oxygen isotopic compositions of vein-filling calcite are similar to those of calcite within the host rock, with vein-filling δ 18 O slightly depleted and δ 13 C slightly enriched. Modeling the fluid isotopic evolution, assuming vein opening and filling amid immobile connate formation water, accounts for these minor but systematic differences, which are attributable to increasing temperature and hydrocarbon maturation. An exception to the above trend is barite, which, despite its low solubility, is systematically enriched in veins with respect to the host rock. It is unclear whether barite precipitation resulted from the influx of external fluids-perhaps deriving from Silurian salt-or from barium mobilized at depth from local clays or organic material.

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Section: Discussionmentioning

confidence: 99%

Fluid evolution in fracturing black shales, Appalachian Basin

Hooker¹,

Cartwright²,

Stephenson³

et al. 2017

Bulletin

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“…Some of the samples from Lower Silurian reservoirs (Warner et al, 2014) display Li concentrations and  7 Li values similar to formation water in Greene Co., PA. We show, however, that upward fluid migration from the Silurian is unlikely for two reasons. First, the Marcellus Shale is presently over-pressured (Aydin and Engelder, 2014), making it unlikely that brine would migrate into the formation. Secondly, results from previous studies using 228 Ra/ 226 Ra (Rowan et al, 2015) support the interpretation that in situ formation water is trapped within the Marcellus Shale whereas 87 Sr/ 86 Sr data suggest that the formation water could be have been water trapped within the shale or adjacent formations (Stewart et al, 2015).…”

Section: Sources Of Elevated LI In Marcellus Shale Formation Watermentioning

confidence: 99%

Factors controlling Li concentration and isotopic composition in formation waters and host rocks of Marcellus Shale, Appalachian Basin

et al. 2016

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In this study, water and whole rock samples from hydraulically fractured wells in the Marcellus Shale (Middle Devonian), and water from conventional wells producing from Upper Devonian sandstones were analyzed for lithium concentrations and isotope ratios ( 7 Li). The distribution of lithium concentrations in different mineral groups was determined using sequential extraction. Structurally bound Li, predominantly in clays, accounted for 75-91 wt. % of total Li, whereas exchangeable sites and carbonate cement contain negligible Li (< 3%). Up to 20% of the Li is present in the oxidizable fraction (organic matter and sulfides). The δ 7 Li values for whole rock shale in Greene Co., Pennsylvania, and Tioga Co., New York, ranged from-2.3 to +4.3‰, similar to values reported for other shales in the literature. The  7 Li values in shale rocks with stratigraphic depth record progressive weathering of the source region; the most weathered and clay-rich strata with isotopically light Li are found closest to the top of the stratigraphic section. Diagenetic illite-smectite transition could also have partially affected the bulk Li content and isotope ratios of the Marcellus Shale. In Greene Co., southwest Pennsylvania, the Upper Devonian sandstone formation waters have  7 Li values of +14.6 ± 1.2 (2SD, n = 25), and are distinct from Marcellus Shale formation waters which have  7 Li of +10.0 ± 0.8 (2SD, n = 12). These two formation waters also maintain distinctive 87 Sr/ 86 Sr ratios suggesting hydrologic separation between these units. Applying temperature-dependent illitilization model to Marcellus Shale, we found that Li concentration in clay minerals increased with Li concentration in pore fluid during diagenetic illite-smectite transition. Samples from north central PA show a much smaller range in both δ 7 Li and 87 Sr/ 86 Sr than in southwest Pennsylvania. Spatial variations in Li and δ 7 Li values show that Marcellus formation waters are not homogeneous across the Appalachian Basin. Marcellus formation waters in the northeastern Pennsylvania portion of the basin show a much smaller range in both δ 7 Li and 87 Sr/ 86 Sr, suggesting long term, cross-formational fluid migration in this region. Assessing the impact of potential mixing of fresh water with deep formation water requires establishment of a geochemical and isotopic baseline in the shallow, fresh water aquifers, and site specific characterization of formation water, followed by long-term monitoring, particularly in regions of future shale gas development.

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“…The role of overpressure on structural style has been previously discussed by several authors who have recognized that high overpressures facilitate the localization of detachments within overpressured units in fold‐and‐thrust belts because of the resulting decrease in frictional strength (Aydin & Engelder, ; Bilotti & Shaw, ; Cobbold et al, , ; Corredor et al, ; Krueger & Grant, ). This has also been demonstrated experimentally using sandbox models (Cobbold & Castro, ; Cobbold et al, , , ; Mourgues & Cobbold, ).…”

Section: Resultsmentioning

confidence: 98%

“…Since many fold-and-thrust belts host prolific hydrocarbon reservoirs (Aydin & Engelder, 2014;Beaudoin et al, 2014;Corredor et al, 2005;Mitra, 1990;Morley, 2009), there is also a strong practical reason to be able to predict both the stress regime and pore pressure distribution prior to drilling (Couzens-Schultz & Azbel, 2014;Hennig et al, 2002).…”

Section: Introductionmentioning

confidence: 99%

Hydromechanical Modeling of Stress, Pore Pressure, and Porosity Evolution in Fold‐and‐Thrust Belt Systems

et al. 2017

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We present coupled, critical state, geomechanical‐fluid flow simulations of the evolution of a fold‐and‐thrust belt in NW Borneo. Our modeling is the first to include the effects of both syntectonic sedimentation and transient pore pressure on the development of a fold‐and‐thrust belt. The present‐day structure predicted by the model contains the key first‐order structural features observed in the field in terms of thrust fault and anticline architectures. Stress predictions in the sediments show two compressive zones aligned with the shortening direction located at the thrust front and back limb. Between the compressive zones, near to the axial plane of the anticline, the modeled stress field represents an extensional regime. The predicted overpressure distribution is strongly influenced by tectonic compaction, with the maximum values located in the two laterally compressive regions. We compared the results at three notional well locations with their corresponding uniaxial strain models: the 2‐D thrust model predicted porosities which are as much as 7.5% lower at 2.5 km depth and overpressures which are up to 6.4 MPa higher at 3 km depth. These results show that one‐dimensional methods are not sufficient to model the evolution of pore pressure and porosity in contractional settings. Finally, we performed a drained simulation during which pore pressures were kept hydrostatic. The predicted geological structures differ substantially from those of the coupled simulation, with no thrust faulting. These results demonstrate that pore pressure is a key control on structural development.

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Revisiting the Hubbert–Rubey pore pressure model for overthrust faulting: Inferences from bedding-parallel detachment surfaces within Middle Devonian gas shale, the Appalachian Basin, USA

Cited by 25 publications

References 86 publications

Fluid evolution in fracturing black shales, Appalachian Basin

Fluid evolution in fracturing black shales, Appalachian Basin

Factors controlling Li concentration and isotopic composition in formation waters and host rocks of Marcellus Shale, Appalachian Basin

Hydromechanical Modeling of Stress, Pore Pressure, and Porosity Evolution in Fold‐and‐Thrust Belt Systems

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