ALBERT

Beschreibung: 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.

Beschreibung: The host rocks of shale gas accumulations act as source, seal and reservoir. They are characterized by complex pore systems with ultra-low to low interparticle permeability and low to moderate porosity. The word ‘shale’ is used in the sense of a geological formation rather than a lithology, so shale gas reservoirs can show marked variations in rock type from claystones, marlstones and mudstones to sandstone and carbonate lithological ‘sweet spots’. The pore space includes both intergranular and intrakerogen porosity. The density of natural fractures varies markedly, and pore throat connectivity is relatively ineffective. Moreover, in-situ gas pore volume has to take account of both free and adsorbed gas, an evaluation exercise that is complicated by pronounced variations in water salinity. All these characteristics present major challenges to the process of petrophysical evaluation. The petrophysical responses to these issues are severalfold. First, a broader calibrating database of core measurements is required at key wells, especially as regards mineralogy, porosity and permeability data, shale/mudstone sample analyses, total organic carbon, gas desorption isotherms, and the analysis of extracted formation waters. Second, at least in the key wells, an extended suite of logs should include an elemental analysis log, magnetic resonance imager, electrical micro-imager, and a dipole sonic log. These databases lead to a rock-typing scheme that takes better account of dynamic properties and fracturability. They also allow reservoir partitioning based on exclusivity of empirical interpretative algorithms, e.g. quartz content vs. producibility. These responses comprise key elements of a functional petrophysical system that encompasses fit-for-purpose interpretation methods, such as a pseudo-Archie approach, i.e. the application of the Archie equations with non-intrinsic exponents. This system is presented as a workflow for application in shale gas reservoirs, for which bulk density retains a major influence on computed gas in place. The benefits of this approach are especially strong in reserves reporting of these unconventional gas reservoirs.