Pressure distribution in a reservoir affected by capillarity and hydrodynamic drive: Griffin Field, North West Shelf, Australia

Underschultz, Jim

doi:10.1111/j.1468-8123.2005.00112.x

Cited by 12 publications

(6 citation statements)

References 15 publications

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“…Processes unrelated to capillarity that may have an additional impact on total seal capacity include hydrodynamic trapping (Ayub & Bentsen 1999;Carruthers 2003;Bent-sen 2005;Underschultz 2005b;Brown & Fisher 2006;Palananthakumar et al 2006), hydraulic resistance sealing (e.g. Brown 2003) and fracture threshold pressure (Watts 1987;Lerche 1993;Clayton & Hay 1994;Bjorkum et al 1998;Teige et al 2005).…”

Section: Discussionmentioning

confidence: 99%

Hydrodynamics and membrane seal capacity

Underschultz¹

2007

Geofluids

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The impact of hydrodynamic groundwater movement on the capacity of seals is currently in debate. There is an extensive record of publication on seals analysis and a similar history on petroleum hydrodynamics yet little work addresses the links between the two. Understanding and quantifying the effects of hydrodynamic flow has important implications for calibrating commonly used seal capacity estimation techniques. These are often based on measurements such as shale gouge, clay smear or mercury porosimitry where membrane sealing is thought to occur. For standard membrane seal analysis, seal capacity is estimated by quantifying capillary pressure-related measurements and calibrating them with a large observational database of hydrocarbon column heights and measured buoyancy pressures. The seal capacity estimation process has historically been adjusted to account for a number of different generic trapping geometries. We define the characteristics of these geometries from a hydrodynamics viewpoint in order to fine-tune the seal capacity calibration process. From theoretical analyses of several simplified trapping geometries, it can be concluded that generally, the high pressure side of the seal should be used as the water pressure gradient with which to calculate buoyancy pressure. Secondly, trap geometries where hydrocarbon is reservoired on both sides of a fault are not useful for estimating across fault seal capacity.

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Section: Discussionmentioning

confidence: 99%

Hydrodynamics and membrane seal capacity

Underschultz¹

2007

Geofluids

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“…Both of these samples have significantly lower permeability (0.1 and 51 md) than the samples below (572 and 900 md); therefore, the low GOI values equate with a zone of reduced oil saturation due to poor reservoir quality. The slight variation in FWL across the Laminaria field is related to the hydraulic head distribution in the underlying aquifer (Underschultz, 2005).…”

Section: Goi Results From the Laminaria Oil Fieldmentioning

confidence: 99%

2. Mechanism and Upfault Seepage and Seismic Expression of Hydrocarbon Discharge Sites from the Timor Sea

Langhi

Zhang

Gartrell

et al. 2013

Hydrocarbon Seepage

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Three-dimensional coupled deformation and fluidflow numerical modeling, charge-history analysis, and seismic imaging of inferred leakage-related geobodies are integrated to investigate the response of a complex set of Jurassic trap-bounding normal faults to extensional reactivation and to assess hydrocarbon upfault seepage on the Laminaria High (Timor Sea, Australian North West Shelf). Fluid inclusion data are consistent with the presence of paleo-oil columns below the current accumulations in the Laminaria and Corallina fields. Evidence for other partially breached (current and paleo-oil column) as well as breached (dry with paleo-oil column) closures across the region implies that active and widespread seepage took place after the time of initial oil charge. The distribution of current and paleo-oil zones, and the location of inferred hydrocarbon leakage indicators defined on 3D seismic data, correlates with the prediction of fault-seal effectiveness based on modeled strain distribution. Within the geologic framework of the Laminaria High area, this distribution suggests that when sufficient reactivation shear strain is accumulated by reservoir faults, ductile deformation might give way to brittle failure in the top seal, allowing active flow pathways to develop and upfault seepage to take place from the reservoir to thief zones or the seafloor. The observations emphasize that strain and upfault fluid-flow partitioning is constrained by prereactivation fault size, lateral fault-tip distributions, and the presence of fault jogs inherited from successive episodes of growth processes. These elements can explain the complex distribution of paleo-and preserved oil columns in the study area and further support Cenozoic tectonic activity as being the firstorder control on trap breaching and hydrocarbon seepage in this region.

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“…These hydraulic effects depend on flow magnitude and direction, as well as the densities of water and hydrocarbons. Underschultz (2005) also state that the tilt relies on a hydraulic gradient. If frictional effects were a contributor to magnitude of tilt, as the flow rates are so small, the effects would be only a minor contributor.…”

Section: Hydrocarbon Contact Tiltingmentioning

confidence: 99%

Integrating a hydrodynamically‐titled OWC and a salt‐withdrawal depositional model to explore the Ula Trend

O’Connor¹,

Rasmussen²,

Swarbrick³

et al. 2011

Geofluids

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The Ula Trend lies on the eastern margin of the Central Trough in the Norwegian North Sea and contains the Ula, Gyda and Tambar oilfields. In this Trend, the development of late Jurassic shallow-marine Ula reservoir sands is complex, because of the deposition of these sands in salt-dissolution features, separated by inverted Triassic pods. In this paper, attribute mapping (derived from newly re-processed 3D seismic surveys) has enabled a predictive model to be established for the presence of the Jurassic sands, corroborated by well data, in salt collapse and sand fairway grabens. This model suggests that the Ula sand is laterally continuous over large areas of the Trend. Pressure data from the Chalk in Ula Field wells, and from Jurassic reservoirs on the Cod Terrace, suggest that these continuous sands of the Ula Trend have significantly less pressure than would be expected for their depth of burial. Pressure escape of this nature is often associated with hydrodynamic aquifers, in which overpressure gradients are demonstrable. In this paper, we have used both virgin and postproduction water pressure data from the vicinity of the Ula Field (as well as a new sedimentological model for the reservoir) to test the applicability of a hydrodynamic aquifer versus other models to explain differing oil-water contacts. We establish that the hydrodynamic and structural spill-points are coincident on the SE of the Ula Field, and that, therefore, hydrocarbons have potentially spilt out of the Ula structure SE towards a series of salt-flank traps, generating prospectivity up-dip. The salt features themselves are considered to act as pressure-release valves or vertical 'leak-points', as Ula sands on their flanks are sufficiently shallow, because of salt movement that overpressures exceed the fracture pressure of the rock, therefore allowing the Ula sands to de-pressurise over geological time, setting up this hydrodynamic flow.

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Pressure distribution in a reservoir affected by capillarity and hydrodynamic drive: Griffin Field, North West Shelf, Australia

Cited by 12 publications

References 15 publications

Hydrodynamics and membrane seal capacity

Hydrodynamics and membrane seal capacity

2. Mechanism and Upfault Seepage and Seismic Expression of Hydrocarbon Discharge Sites from the Timor Sea

Integrating a hydrodynamically‐titled OWC and a salt‐withdrawal depositional model to explore the Ula Trend

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