Hydrodynamics and hydrocarbon trapping: Concepts, pitfalls and insights from case studies

Wendebourg, Johannes; Biteau, Jean-Jacques; Grosjean, Yves

doi:10.1016/j.marpetgeo.2018.05.015

Cited by 11 publications

(7 citation statements)

References 22 publications

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“…Hydraulic head and its map‐view realization (potentiometric surface) is a simple but powerful tool for understanding pressure distribution and hydrodynamics. Hydraulic heads and potentiometric surfaces can describe map‐view variations in fluid pressure and related lateral fluid flow in sedimentary basins (e.g., Cohen & Cherry, 2020; Dennis et al, 2000; Wendebourg et al, 2018).…”

Section: Hydrostatic Pressure Gradient Determinationmentioning

confidence: 99%

“…Classically described for deep, confined reservoirs by Hubbert (1953), hydrodynamic conditions are important in the exploration and management of any subsurface fluid project because free water levels or contacts between immiscible fluids become tilted in proportion to the hydraulic head gradients. The direction of flow may be into the basin with water ingress at the basin margin (e.g., Al‐Mahmoud, 2017, 2021), or out of the basin due to overpressure (e.g., compaction) in the basin centre (e.g., Dennis et al, 2000; Wendebourg et al, 2018) or both (e.g., Bachu, 1995a; Bachu & Hitchon, 1996). The magnitude of hydrodynamic effect in relatively deep confined reservoirs is reasonably well constrained to the order of 1 psi / km laterally (e.g., Bachu, 1995b; Dennis et al, 2000; Green et al, 2014; Larkin, 2010; Neuzil, 1995; Wendebourg et al, 2018).…”

Section: Abnormal Pressuresmentioning

confidence: 99%

“…The direction of flow may be into the basin with water ingress at the basin margin (e.g., Al‐Mahmoud, 2017, 2021), or out of the basin due to overpressure (e.g., compaction) in the basin centre (e.g., Dennis et al, 2000; Wendebourg et al, 2018) or both (e.g., Bachu, 1995a; Bachu & Hitchon, 1996). The magnitude of hydrodynamic effect in relatively deep confined reservoirs is reasonably well constrained to the order of 1 psi / km laterally (e.g., Bachu, 1995b; Dennis et al, 2000; Green et al, 2014; Larkin, 2010; Neuzil, 1995; Wendebourg et al, 2018). This seemingly small hydrodynamic signal obviously rises to tens or hundreds of psi with increasing well spacing and may be very clear in regional datasets in continuous reservoir filled with a fluid of consistent composition (e.g., Bachu & Underschultz, 1993; Wendebourg et al, 2018).…”

Section: Abnormal Pressuresmentioning

confidence: 99%

“…The magnitude of hydrodynamic effect in relatively deep confined reservoirs is reasonably well constrained to the order of 1 psi / km laterally (e.g., Bachu, 1995b; Dennis et al, 2000; Green et al, 2014; Larkin, 2010; Neuzil, 1995; Wendebourg et al, 2018). This seemingly small hydrodynamic signal obviously rises to tens or hundreds of psi with increasing well spacing and may be very clear in regional datasets in continuous reservoir filled with a fluid of consistent composition (e.g., Bachu & Underschultz, 1993; Wendebourg et al, 2018).…”

Section: Abnormal Pressuresmentioning

confidence: 99%

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Hydrostatic pore water pressure revisited

Stewart

Albertz

2022

Basin Research

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Hydrostatic or “normal” pressure can be easily visualized as a water column with pressure given by ρgh and any departures classified as abnormal pressure. This is the basis for commonly used hydrostatic pressure depth trends in sedimentary basins that are constructed on assumptions of constant gradients and are datumed at mean sea level or ground level. But the straightforward water column concept does not upscale in a simple way to sedimentary basins where the zones of interest are several thousands of metres below the land or sea surface. Sedimentary basins are heterogeneous, including stacked, confined reservoirs and variations in pore water composition. It is possible to construct pressure‐depth profiles that honour the geology and hydrostratigraphy of a basin and these give different hydrostatic baselines from simple constant gradients hung from familiar local datums such as ground level. Key steps are using a reservoir‐specific datums such as the water table or potentiometric surface relevant to that unit, then building a pressure‐depth trend that represents the pore fluid salinity variation and density profile throughout the reservoir unit. At a given depth, this version of hydrostatic may predict pressures several hundred psi different from a single density gradient hung from a datum local to the well, and exhibit a notched profile reflecting the geological and hydrological stratigraphy. This construct redefines normal and abnormal pore fluid pressures in sedimentary basins. The impacts of this alternative approach to sedimentary basin hydrostatics, even if data are limited and pressure profiles have to be framed probabilistically, extend to many aspects of studying and interacting with fluid systems in sedimentary basins including basin modelling, petroleum systems analysis, well planning and well operations.

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Section: Hydrostatic Pressure Gradient Determinationmentioning

confidence: 99%

Section: Abnormal Pressuresmentioning

confidence: 99%

Section: Abnormal Pressuresmentioning

confidence: 99%

Section: Abnormal Pressuresmentioning

confidence: 99%

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Hydrostatic pore water pressure revisited

Stewart

Albertz

2022

Basin Research

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“…However, this topic should be used with caution in case of some petroleum traps (Magara, 1981). In addition, the hydrodynamic flow in the oil and gas reservoirs tilts the fluid contacts and thus has a major impact on hydrocarbon inplace (Thomasen and Jacobsen, 1994, Dennis et al, 2000, Tozer and Borthwick, 2010, Yang and Mahmoud, 2016, Wendebourg et al, 2018, Amirsardari et al, 2021. Thus, Hydrodynamic flow in geological basins have been described in detail by many geoscientists and petroleum engineers emphasizing the fact that water flow mainly caused by their pressure potential differences.…”

Section: Introductionmentioning

confidence: 99%

A Simplified Modeling Approach of Compaction-Induced Groundwater Hydrodynamic Activity in Hydrocarbon Reservoirs

Afsari¹,

Amirsardari

Alali³

2023

Preprint

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Groundwater flow has been identified as a cause of hydrocarbon trapping in geological basins. In sedimentary basins, two main drives for hydrodynamic flow can be distinguished: gravity-driven (centripetal flow) and compaction-driven (centrifugal flow). Some experts believe that the centrifugal phenomenon is a currently active mechanism in some hydrocarbon reservoirs. However, the time duration in which the centrifugal hydrodynamic flow is active has not been well studied by researchers. In this article using numerical modelling of compaction-induced hydrodynamic flow, we estimate a duration time in which this kind of flow is active. With comparison of the time of diminution of centrifugal flow to geological time scale of hydrocarbon reservoirs, it is concluded that centrifugal hydrodynamic flow cannot be currently active. Also, all the phenomena influenced by hydrodynamic activity in petroleum reservoirs including tilted fluid contact and also hydrodynamic trapping are as a result of gravity-driven hydrodynamic activity not compaction-driven.

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