Hege M. Nordgård Bolås

Stress-dependent elastic properties of shales: measurement and modeling

Despite decades of research, current understanding of elastic properties of shales is insufficient as it is based on a limited number of observations caused by the time-consuming nature of testing resulting from their low permeability. Though it is well known that shales are highly anisotropic and assumed to be transversely isotropic (TI) media, few laboratory experiments have been carried out for measuring the five elastic constants that define TI media on well-preserved shales. Many previous measurements were made without control of pore pressure, which is crucial for the determination of shale elastic properties.

Origin of overpressures in shales: Constraints from basin modeling

Techniques for detection, evaluation, and prediction of pore pressures in low-permeability rocks and equations for fluid-pressure computations in most integrated basin-modeling software are based on relationships between porosity and effective stress in shales. However, recent data show that overpressured shales in the North Sea do not exhibit higher porosities than the normally pressured shales of the same formation at similar depths.To further evaluate the existence of porosity vs. effective stress relationships in shales, fluid-flow simulations and porosity modeling in a typical high-pressure and high-temperature well in the North Sea were undertaken. The parameters in the permeability and porosity equations were adjusted until a satisfactory fit was achieved between the observed and modeled porosity and fluid pressure at present. However, the modeled porosity and pore pressure vs. depth history of the sediments deviated significantly from known porosity and pore pressure vs. depth relationships that have been observed in North Sea shales and elsewhere today.Because the results from basin modeling based on porosity-stress relationships were unacceptable, irrespective of parameter choices, and the well data from the North Sea show no signs of elevated porosities in the overpressured shales, it is inferred that effective stress-driven compaction alone has not generated the hard overpressures observed in deeply buried North Sea shales. These conclusions are suggested to be generally applicable to shales with low porosities and hard overpressures worldwide, both because of the physics involved and because similar results can be extracted from published modeling in the Niger Delta.

Consequences of Water Level Drops for Soft Sediment Deformation and Vertical Fluid Leakage

Both water level drops and erosion have previously been suggested as causes of fluid overpressures in the subsurface. Quantification of the relevance of these processes to supra-lithostatic fluid pressure formation with a wide selection of input parameters is lacking, and thus desired. The magnitudes and drop times that are required for water level drops to result in supra-lithostatic pore pressures in a variety of situations are calculated. Situations with pore fluids consisting of water, water with dissolved methane, water with a gas hydrate layer and dissolved methane in the underlying sediments, and water with dissolved methane, a gas hydrate layer, and free gas accumulation below the hydrate layer are separately addressed. The overpressure formation from reservoir gas expansion is also simulated. The simulation results demonstrate that high fluid overpressures can develop in a rock as a response to a water level drop without the presence of gas, provided that the rock has a sufficiently low compressibility. The contribution to fluid overpressuring is however dramatically increased if the pore water is saturated with methane prior to the water level drop, and is further amplified by the presence of gas hydrates and free gas accumulations beneath such hydrates. Gas expansion in reservoirs should be expected to significantly increase the fluid overpressures in shallow, sealed pressure compartments that experience erosion or water level drops, even if the water level drop duration exceeds one million years. Enough relationships between the calculated overpressure formation and the main controlling factors are provided in order to enable readers to make inferences about a variety of geological settings. Analyses of simulation results prompt us to suggest that pockmarks are likely to be triggered by gas expansion in vertical fluid migration pathways, that the giant craters at the seabed west of Albatross South in the Barents Sea result from hydrate dissociation, and that overpressure build-up due to gas expansion has contributed to reservoir overpressuring in many eroded basins, including the Hammerfest Basin in the Barents Sea.

Capillary resistance and trapping of hydrocarbons: a laboratory experiment

Low permeability cap rocks retain oil by capillary forces when the pore throats of the seals are sufficiently small to prevent a flux of oil into the cap rock. In order to investigate the influence of aquifer overpressures on oil retention, water pressure was applied to a water-wet, highly permeable (1988 mD) core sample, which was oil-saturated to irreducible water saturation Swi and mounted with a low-permeability and water-wet membrane at the outlet. A water pressure difference of 0.5 MPa was applied across the core. This pressure was high enough to ensure fluid flow through the sample. The experiment was designed to see whether the water pressure would force oil through the membrane or if capillary forces at the sandstone–membrane interface would retain the oil, in which case water flow might take place in the (residual) water in the core and through the membrane. The experiment showed that oil was kept in place by capillary forces while water flowed through the core and the membrane. Accordingly, residual water can move through sandstones that are saturated to Swi. The experiments also demonstrated that the permeability associated with this residual water is high enough to prevent overpressures in the aquifer below the oil–water contact from pushing oil through a membrane seal. Thus, even for this highly permeable sandstone, the overpressure in the aquifer will not cause capillary seal failure.

Hydrocarbon leakage processes and trap retention capacities offshore Norway

Associations between high overpressures and sparse hydrocarbon occurrence are commonly ascribed to hydrocarbon leakage through pressure-induced fractures in the cap rock. However, several hydrocarbon traps in the North Viking Graben area in the North Sea still contain abundant commercial volumes of hydrocarbons at very high pore pressures. By contrast, a majority of the overpressured structures at the Halten Terrace further to the north have leaked hydrocarbons, even at considerably lower overpressures. A selection of wells in the North Viking Graben and the Halten Terrace areas was investigated to find possible explanations for these observations. Distinct regional differences emerged, as the emptied reservoirs at the Halten Terrace generally have higher retention capacities than the overpressured discoveries in the North Viking Graben area. Thus, there appears to be a lack of any clear relationship between structures emptied of hydrocarbons and low retention capacities, which could be expected if pressure-induced fracturing of the cap rock was the main process of the hydrocarbon leakage. The regional differences in retention capacities were mainly attributed to different leakage processes in the two basins. Stress history variations are suggested to be the main controlling factor of these leakage processes.