Hydromechanical coupling in geologic processes

Neuzil, Christopher E.

doi:10.1007/s10040-002-0230-8

Cited by 139 publications

(44 citation statements)

References 132 publications

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“…Fractures control the permeability of many reservoirs and the relation between fracturing and fluid flow is currently a topic of extensive research (e.g., Vigneresse, 2001;Berkowitz, 2002;Labaume et al, 2002;Neuzil, 2003;Dietrich et al, 2005;Dresen et al, 2006;Sahimi, 2011;Adler et al, 2012). Fractures are very efficient paths for the migration of hydrocarbons in reservoirs (Mandl and Harkness, 1987;Aydin, 2000;Nunn and Meulbroek, 2002).…”

Section: Reservoir Fractures and Fluid Transport Models Of Reservoir mentioning

confidence: 99%

Effects of mechanical layering on hydrofracture emplacement and fluid transport in reservoirs

2013

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Fractures generated by internal fluid pressure, for example, dykes, mineral veins, many joints and man-made hydraulic fractures, are referred to as hydrofractures. Together with shear fractures, they contribute significantly to the permeability of fluid reservoirs such as those of petroleum, geothermal water, and groundwater. Analytical and numerical models show that-in homogeneous host rocks-any significant overpressure in hydrofractures theoretically generates very high crack tip tensile stresses. Consequently, overpressured hydrofractures should propagate and help to form interconnected fracture systems that would then contribute to the permeability of fluid reservoirs. Field observations, however, show that in heterogeneous and anisotropic, e.g., layered, rocks many hydrofractures become arrested or offset at layer contacts and do not form vertically interconnected networks. The most important factors that contribute to hydrofracture arrest are discontinuities (including contacts), stiffness changes between layers, and stress barriers, where the local stress field is unfavorable to hydrofracture propagation. A necessary condition for a hydrofracture to propagate to the surface is that the stress field along its potential path is everywhere favorable to extension-fracture formation so that the probability of hydrofracture arrest is minimized. Mechanical layering and the resulting heterogeneous stress field largely control whether evolving hydrofractures become confined to single layers (stratabound fractures) or not (non-stratabound fractures) and, therefore, if a vertically interconnected fracture system forms. Non-stratabound hydrofractures may propagate through many layers and generate interconnected fracture systems. Such systems commonly reach the percolation threshold and largely control the overall permeability of the fluid reservoirs within which they develop.

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Section: Reservoir Fractures and Fluid Transport Models Of Reservoir mentioning

confidence: 99%

Effects of mechanical layering on hydrofracture emplacement and fluid transport in reservoirs

2013

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“…Note that weathering reactions of sedimentary rocks tend to reverse what happened during the previous burial diagenesis event. There are also physical consequences of uplift and removal of overburden, including the development of decompaction joints (Neuzil 2003) that serve to allow the fluids that cause weathering to penetrate metres or even 10's of metres below the surface.…”

Section: Telodiagenesis (Uplift-related Diagenesis)mentioning

confidence: 99%

Petroleum reservoir quality prediction: overview and contrasting approaches from sandstone and carbonate communities

et al. 2018

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Abstract:The porosity and permeability of sandstone and carbonate reservoirs (known as reservoir quality) are essential inputs for successful oil and gas resource exploration and exploitation. This chapter introduces basic concepts, analytical and modelling techniques and some of the key controversies to be discussed in 20 research papers that were initially presented at a Geological Society conference in 2014 titled 'Reservoir Quality of Clastic and Carbonate Rocks: Analysis, Modelling and Prediction'. Reservoir quality in both sandstones and carbonates is studied using a wide range of techniques: log analysis and petrophysical core analysis, core description, routine petrographic tools and, ideally, less routine techniques such as stable isotope analysis, fluid inclusion analysis and other geochemical approaches. Sandstone and carbonate reservoirs both benefit from the study of modern analogues to constrain the primary character of sediment before they become a hydrocarbon reservoir. Prediction of sandstone and carbonate reservoir properties also benefits from running constrained experiments to simulate diagenetic processes during burial, compaction and heating. There are many common controls on sandstone and carbonate reservoir quality, including environment of deposition, rate of deposition and rate and magnitude of sea-level change, and many eogenetic processes. Compactional and mesogenetic processes tend to affect sandstone and carbonate somewhat differently but are both influenced by rate of burial, and the thermal and pressure history of a basin. Key differences in sandstone and carbonate reservoir quality include the specific influence of stratigraphic age on seawater composition (calcite v. aragonite oceans), the greater role of compaction in sandstones and the greater reactivity and geochemical openness of carbonate systems. Some of the key controversies in sandstone and carbonate reservoir quality focus on the role of petroleum emplacement on diagenesis and porosity loss, the role of effective stress in chemical compaction (pressure solution) and the degree of geochemical openness of reservoirs during diagenesis and cementation. This collection of papers contains case study-based examples of sandstone and carbonate reservoir quality prediction as well as modern analogue, outcrop analogue, modelling and advanced analytical approaches.Gold Open Access: This article is published under the terms of the CC-BY 3.0 license.Porosity and permeability (reservoir quality) exert fundamental controls on the economic viability of a petroleum accumulation (Blackbourn 2012).They need to be quantified from basin access and exploration, via appraisal and field development through secondary and tertiary recovery in order to

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“…The CO 2 storage capacity of pressure-constrained systems depends on the sustainable pressure buildup that a given formation-seal system is expected to tolerate without geomechanical degradation (such as microfracturing and/or fault reactivation) of the sealing structures (USEPA, 1994;Neuzil, 2003;Rutqvist and Tsang, 2002;. Fluid pressure in the storage formation may also be constrained to limit the pressure driving forces into neighboring formations, or to account for potential concerns about seismicity.…”

Section: Sustainable Pressure Buildupmentioning

confidence: 99%

A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

Zhou

Birkhölzer

Tsang

et al. 2008

International Journal of Greenhouse Gas Control

392

281

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Hydromechanical coupling in geologic processes

Cited by 139 publications

References 132 publications

Effects of mechanical layering on hydrofracture emplacement and fluid transport in reservoirs

Effects of mechanical layering on hydrofracture emplacement and fluid transport in reservoirs

Petroleum reservoir quality prediction: overview and contrasting approaches from sandstone and carbonate communities

A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

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