Christian Hermanrud

Constraints on the in situ density of CO2 within the Utsira formation from time-lapse seafloor gravity measurements

Constraints on the in situ density of CO2 within the Utsira formation from time-lapse seafloor gravity measurements

Estimates of virgin rock temperature derived from BHT measurements: Bias and error

Virgin rock temperatures are important to hydrocarbon exploration, as these temperatures are necessary for the computation of source rock temperatures, and for hydrocarbon generation computations. Several methods have been developed for determination of virgin rock temperatures from maximum temperatures recorded during logging in the past decades. This paper describes an investigation where the calculated virgin rock temperatures from several different methods were examined for bias and accuracy using 18 different measurement series at the Oseberg field. The temperatures were corrected for different depths of burial, and then compared with each other and with drill stem test (DST) measurements to investigate the inaccuracy of the methods. The most advanced methods gave values close to the DST temperatures on average, but with standard deviations as high as 9 degrees C. The less advanced models (like the Horner plot method) have systematically too low virgin rock temperatures (by about 8 degrees C) for the Oseberg field, with standard deviations of 8 degrees C.The errors in calculated virgin rock temperatures are large enough to completely alter predictions of hydrocarbon generation in an area. The large errors are attributed to poor quality data and to physical effects that are not properly taken into account in the temperature calculations. Improved sampling of temperature data can probably reduce the errors to some extent.

Seismic modeling of gas chimneys

We propose a simple acoustic model explaining the main features of gas chimneys. The main elements of the model consist of gas diffusing from a connected fracture network and into the surrounding shale creating an inhomogeneous gas saturation. The gas saturation results in an inhomogeneous fluctuating compressional velocity field that distorts seismic waves. We model the fracture network by a randomwalk process constrained by maximum fracture length and angleofthefracturewithrespecttothevertical.Thegassaturation is computed from a simple analytical solution of the diffusion equation, and pressure-wave velocities are locally obtained assuming that mixing of shale and gas occurs on a scalemuchsmallerthanseismicwavelengths.Syntheticseismic sections are then computed using the resulting inhomogeneous velocity model and shown to give rise to similar deterioration in data quality as that found in data from real gas chimneys.Also, synthetic common-midpointCMPgathers show the same distorted and attenuated traveltime curves as those obtained from a real data set. The model shows clearly thatthefeaturesofgaschimneyschangewithgeologicaltime a model parameter in our approach, the deterioration of seismicwavesbeingsmallestjustafterthecreationofthegas chimney. It seems likely that at least some of the features of gas chimneys can be explained by a simple elastic model in combinationwithgasdiffusionfromafracturenetwork.

Formation temperature estimation by inversion of borehole measurements

We describe a new numerical method that uses inverse methods to model thermal stabilization of a borehole after drilling mud circulation has stopped. The following five geophysical parameters can be estimated from the method: (1) true formation temperature (Tf); (2) mud temperature (Tm) at the time the mud circulation stops; (3) thermal invasion distance (R) into the formation before the formation is at the true formation temperature(Tf); (4) formation thermal conductivity (K) perpendicular to the borehole; and (5) efficiency factor (F) for heating mud in the borehole after mud circulation has stopped. Crucial input data for the model are the temperature measurements with shut‐in time taken at a fixed depth, more than two measurements being required, and the mud temperature at the surface at the time circulation stops. Other input data include the radius of the borehole, and the densities and specific heats of the drilling mud and of the formation on which the temperature measurements are made. Applicatio...

The lack of relationship between overpressure and porosity in North Sea and Haltenbanken shales

Abstract Disequilibrium compaction (undercompaction) is probably the most accepted mechanism for explaining overpressured formations. This mechanism relies on the hypothesis that overpressured shales have higher porosity than normally pressured shales for a given depth. Converted to porosity units, log response data from two Jurassic shales at Haltenbanken and nine Cretaceous and Tertiary shales in the Norwegian sector of the North Sea have been investigated to see whether such a relationship exists in these areas. The depth of the studied shale formations varies between 0.5-5 km. The degree of overpressuring within one formation typically varies by 20 MPa. The log response data show that neither the porosity of massive North Sea shales (derived from sonic and density logs) nor the porosity of Haltenbanken intra-reservoir shales (derived from density and neutron logs) differ significantly between the overpressured and normally pressured stratigraphic units. Distinct differences between the pressure regimes are, however, apparent in the resistivity and sonic log data from deeply buried shales at Haltenbanken. These differences do not reflect porosity variations and are interpreted to reflect textural changes resulting from the overpressuring. These observations demonstrate that the Haltenbanken and North Sea shales do not conform to an undercompaction mechanism for overpressuring, as the overpressured wells fail to show elevated porosity. On the contrary, each formation seems to have been individually compacted according to burial depth, independent of pressure regimes.

Evidence for large-scale methane venting due to rapid drawdown of sea level during the Messinian Salinity Crisis

We report the discovery, from three-dimensional seismic mapping, of a field of pockmarks buried at present depths of ∼4 km in the Levant Basin (southeastern Mediterranean). The pockmarks cover an area of ∼1000 km 2 , have diameters as great as 2 km, and erode as much as 200 m into their substrate of deep-water clastic sediments, which immediately predate the Messinian Salinity Crisis (MSC, ca. 6.2–5.5 Ma). These craters are filled by the basal units of the Messinian evaporites, thus implying they formed at or close to the time of the earliest major drawdown of sea level. All the pockmarks are developed at a single, regionally correlatable surface, Horizon N, which is observed throughout the Mediterranean to coincide with the onset of the MSC. In the study area, this surface formed by erosion and drawdown with a magnitude of 900–1000 m. We propose that this rapid basinal drawdown led to a dramatic increase of the shallow subsurface pore-fluid overpressure regime in the mostly fine-grained pre-Messinian sediments. Subsequent pressure release then resulted in high flux fluid venting, sediment remobilization, and pockmark formation. The spatial association of the craters with an underlying canyon suggests that their formation is linked to biogenic methane generation. The model of drawdown-induced overpressuring and remobilization may be applicable to many other evaporitic basins, and represents a novel mechanism for inducing large-scale sediment remobilization of shallow buried depositional systems at the earliest stages of salt basin development.

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.