Using Traditional Methods to Predict Pore Pressure in Devonian Black Shale Basins of North East British Columbia

Green, Sam; Loeffler, J; Clarke, Sally; Thurston, David

doi:10.15530/urtec-2018-2904084

Cited by 2 publications

(1 citation statement)

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“…A key area of focus in the industry at present is unconventional plays; these are an emerging element of the subsurface characterization workflow. There have been several papers that have shown it is possible to build a model that predicts the in situ pore pressure (Zhang and Wieseneck, 2011; Couzens‐Schultz et al ., 2013; Green et al ., 2018a; 2018b) but in all these models the solutions are empirical and are based on using classical methods, primarily velocity–effective stress cross‐plotting (Bowers, 1994), and fitting a power law through the data.…”

Section: Discussionmentioning

confidence: 99%

Correcting density/sonic logs for total organic carbon to reduce uncertainty in pore pressure prediction

Green¹,

Vernik²

2020

Geophysical Prospecting

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Pore pressure prediction in shales undergoing compaction, including both mechanical and chemical processes, is customarily related to the mechanism referred to disequilibrium compaction. However, even when this mechanism is established and the normal compaction trend in sonic velocity, as a proxy for shale porosity, is well constrained, the pore pressure prediction may be in error because of the lithological variation in shale composition. The presence of solid organic matter in excess amounts in shale formations that have never been exposed to the pressure–temperature conditions in the oil window is an example of these lithological effects, causing marked overprediction of pore pressure even in thermally immature mudrocks. This necessitates implementation of bulk density and sonic velocity log corrections in organic‐rich shales prior to performing standard pore pressure prediction workflows. In this paper, it is shown how these corrections can be made and the outcomes of the pore pressure prediction can be dramatically improved by using combination of rock physics models relating bulk density to total organic carbon and P‐wave velocity to bulk density in organic‐rich and conventional shales, respectively. To illustrate the workflow, a case study from a well drilled through the Kimmeridge Clay Formation in the North Sea, a well‐recognized source rock with total organic carbon content in the 2%–12% range and significant variation in clay content from 25% to 60%, both of which strongly affect the most commonly utilized log responses recorded in this formation. Using this old but data‐rich well, the importance of accounting for both total organic carbon and clay content variations in pore pressure prediction is demonstrated. It is also recognized that this workflow does not immediately apply to unconventional shale plays, where the pore pressure generation mechanisms are more complex and cannot be solely ascribed to compaction disequilibrium.

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Section: Discussionmentioning

confidence: 99%

Correcting density/sonic logs for total organic carbon to reduce uncertainty in pore pressure prediction

Green¹,

Vernik²

2020

Geophysical Prospecting

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Overpressure estimation and productivity analysis for a Marcellus Shale gas reservoir, southwest Pennsylvania: A case study

et al. 2018

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It is well established that geology, geomechanics, and completion play an important role in gas productivity from shale formations. In particular, overpressured shale — along with higher fracture intensity — generally correlates with higher production rates. Conventional pore-pressure prediction techniques do not work well for black shale formations, primarily because a basin has often experienced multiple episodes of tectonic activity and subsequent overpressure generation; secondly, because the recorded petrophysical logs for pore-pressure estimation are significantly affected by the presence of organic content and gas. Overpressure mechanisms and distribution are studied for the Middle Devonian Marcellus Shale Formation of the Appalachian Basin in Pennsylvania to understand their relationship with well productivity. A sonic velocity-density crossplot does not reveal a clear picture of overpressure generation, primarily due to complex geologic history and distinct compositional variation between Marcellus Shale and overburden shale. 1D pore pressure was estimated from sonic velocity using traditional methods with pressure reference trend for the Marcellus Shale interval in the drilled wells and calibrated to the available in situ pressure measurements. 3D pore pressure was then estimated with upscaled 1D pore-pressure profiles and 3D seismic velocity data. Results suggest that the area having higher overpressure of about 160 psi produces about 55% more gas than the lower overpressure area. Further, understanding the spatial variation of overpressure in the study area may facilitate better field development planning.

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Using Traditional Methods to Predict Pore Pressure in Devonian Black Shale Basins of North East British Columbia

Cited by 2 publications

References 1 publication

Correcting density/sonic logs for total organic carbon to reduce uncertainty in pore pressure prediction

Correcting density/sonic logs for total organic carbon to reduce uncertainty in pore pressure prediction

Overpressure estimation and productivity analysis for a Marcellus Shale gas reservoir, southwest Pennsylvania: A case study

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