Petroleum Geoscience - Volume 20, Issue 3, 2014

Hydrocarbon leakage is a major exploration challenge in the western Hammerfest Basin. Most exploration failures in the area have been attributed to leakage; hydrocarbon-bearing traps are rarely filled to their structural capacity, and almost all traps have hydrocarbon shows down to their structural spillpoint or below.

We have investigated to what extent the hydrocarbon column heights can be explained by vertical leakage along faults or at fault intersections. For the fields that we evaluated we observe that: (a) all dry structures have fault intersections at top reservoir level up dip of the well position: (b) the only structure where no faults intersect at top reservoir level is the only structure that is clearly filled to structural spillpoint; and (c) all fluid contacts in underfilled structures broadly coincide with the position of intersecting faults. The underfilled structures have less than two fault intersections up dip and above the gas-bearing reservoir. We suggest that vertical leakage at fault intersections has exerted a main control on the position of the gas–water contacts in the western Hammerfest Basin, and therefore that hydrocarbon column-height predictions can be improved by addressing the positions of such intersections at the top reservoir surface.

Future geological CO2 sequestration in the Gippsland Basin is contingent upon an effective regional top seal; potentially provided by the late Oligocene–early Miocene Lakes Entrance Formation. This study integrates various top-seal assessment methodologies into a workflow to estimate the efficiency of the Lakes Entrance Formation as a top seal. Factors related to, for example, top-seal lithology, shale volume, carbonate content and fracture density, and factors relating to the faults that cut the top seal, fault-zone shale content, strain, slip-tendency, etc., are compared to hydrocarbon leakage and seepage indicators reported in the study area. The factors that best correlate with reported leakage indicators are combined to map the spatial risk variation.

While the study indicated that the ultimate control on top-seal efficiency is the formation’s membrane seal capacity; it also highlighted the spatial correlation between leakage indicators and some fault-related factors, suggesting that faults are key to top-seal bypass in much of the Gippsland Basin. Fault-zone shale content proved the dominant fault-related factor; as such, it can be concluded in the Gippsland Basin, at least, that a fault-zone shale content of less than 0.3 is the dominant factor with regard to faults enabling fluids to bypass top seals.

The Fjerritslev Formation in the Norwegian–Danish Basin forms the main seal to Upper Triassic–Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjælland, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian–Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry–mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6–10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer–Emmett–Teller (BET)-specific surface-area measurements using Kozeny’s formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two–three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot’s coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.

The initialization of a reservoir simulator calls for the populating of a three-dimensional dynamic grid-cell model using subsurface data and interrelational algorithms that have been synthesized to be fit for purpose. These prerequisites are rarely fully satisfied in practice. This paper sets out to strengthen initialization through four key thrusts, all of which seek to optimize the bridgehead between reservoir geoscience and reservoir engineering, and thereby maximize value from reservoir simulation. The first addresses representative data acquisition, which includes the key-well concept as a framework for the cost-effective incorporation of free-fluid porosity and permeability within an initialization database. The second concerns the preparation of these data and their products for populating the static and dynamic models. Important elements are dynamically conditioned net-reservoir cut-offs, recognition of primary flow units, and establishing interpretative algorithms at the simulator grid-cell scale for application over net-reservoir zones. The third thrust is directed at the internal consistency of capillary character, relative permeability properties and petrophysically-derived hydrocarbon saturations over net reservoir. This exercise is central to the simulation function and it is an integral component of hydraulic data partitioning. The fourth concerns the handling of formation heterogeneity and anisotropy, especially from the standpoint of directional parametric averaging and interpretative algorithms. These matters have been synthesized into a workflow for optimizing the initialization of reservoir simulators. In so doing, a further important consideration is the selection of the appropriate procedures that are available within and specific to different software packages.

It is the authors’ experience that implementation of these thrusts has demonstrably enhanced the authentication of reservoir simulators through more readily attainable history matches with less required tuning. This outcome is attributed to a more systematic initialization process with a lower risk of artefacts. Of course, these benefits feed through to more assured estimates of ultimate recovery and, thence, hydrocarbon reserves.

This study examines the four-dimensional (4D) seismic signatures from multiple seismic surveys shot during gas exsolution and dissolution in a producing hydrocarbon reservoir, and focuses in particular on what reservoir information may be extracted from their analysis. To aid in this process, hydrocarbon gas properties and behaviour are studied, and their relationship to the fluid-flow physics is understood using numerical simulation. This knowledge is then applied to interpret the seismic response of a turbidite field in the UK Continental Shelf (UKCS). It is concluded that for a repeat seismic survey shot 6 months or more after a pressure change above or below bubble point (as in our field case), the gas-saturation distribution during either exsolution or dissolution exists in two fixed saturation conditions defined by the critical and the maximum possible gas saturation. Awareness of this condition facilitates an interpretation of the data from our field example, which has surveys repeated at intervals of 12–24 months, to obtain an estimate of the critical gas saturation of between 0.6 and 4.0%. These low values are consistent with a range of measurements from laboratory and numerical studies in the open literature. Our critical gas-saturation estimate is also in qualitative agreement with the solution gas–oil ratios estimated in a material balance exercise using our data. It is not found possible to quantify the maximum gas saturation using the 4D seismic data alone, despite the advantage of having multiple surveys, owing to the insensitivity of the seismic amplitudes to the magnitude of this gas saturation. Assessment of the residual gas saturation left behind after secondary gas-cap contraction during the dissolution phase suggests that small values of less than a few per cent may be appropriate. The results are masked to some extent by an underlying water flood. It is believed that the methodology and approach used in this study may be readily generalized to other moderate- to high-permeability oil reservoirs, and used as input in simulation model updating.