Reactive Pore Network Modeling technology to evaluate the impact of diagenesis on the petrophysical properties of a rock

Abstract

Abstract Sedimentary reservoir rocks often present heterogeneous pore structures that are inherently related to the original rock texture and subsequent diagenetic alterations. Such alterations are governed by the original rock texture, the involved fluids, the flow history, and the physico-chemical conditions. Throughout the paragenesis, alternating dissolution and precipitation caused by changes in chemical and thermodynamic conditions may lead to heterogeneous rock properties at both local and reservoir scale. In the absence of cored plugs to measure the petrophysical properties and multiphase flow properties, a numerical tool that simulates these data by predicting the pore structure evolution of the original grain deposit is of great interest for the petroleum industry and the reservoir characterization studies. A Pore Network Model, which is an efficient tool to account for phenomena occurring at the pore scale, is used to mimic the diagenetic cycle. The approach is based on three steps. The first step consists in replacing the original complex pore structure of real porous media by a conceptual network. The second step consists in solving the governing equations of the precipitation/dissolution phenomena in the conceptual 3D pore network, and deducing the local reactive fluxes and the motion of the fluid-solid interface. The third step consists in updating the pore structure and calculating the petrophysical properties of the altered porous media. Those steps are repeated in order to mimic a given diagenetic scenario. Finally, the petrophysical properties and multiphase flow properties of the current porous media are calculated. The impact of the diagenetic scenario on the current pore structure heterogeneity and consequently on the petrophysical properties and multiphase flow properties have been investigated. The permeability and porosity evolution during a given diagenetic scenario are calculated and analyzed as a function of the relevant dimensionless numbers (Peclet and Damköhler numbers). The correlation between these numbers and the dissolved/precipitated layer thickness distribution is shown. Consequently, for a same original grain deposit, the permeability-porosity relationship of a sedimentary reservoir rock depends on the diagenetic and flow history. Current rocks with a same porosity may have drastically different permeabilities and multiphase flow properties. Introduction Sedimentary reservoir rocks often present heterogeneous pore structures that are inherently related to the original rock texture and subsequent diagenetic alterations. For instance a grainstone texture (cf. Dunham; 1962) is a rock made up of allochems (grains) with no mud matrix (Fig. 1.a). The intergranular pores will, therefore, possess sizes that are inherently related to the size the grains. In other words, the coarser the grains will be, the larger the pores and the higher permeability will result. On the other hand, mudstone, wackestone and packstone textures (cf. Dunham; 1962) relate to rocks with considerable mud matrix (Fig. 1.b). Hence, the allochems appear floating in a muddy background. Carbonate mud is made up of microcrystalline calcite crystals (size <4µm), which results in a considerable intercrystalline porosity, yet the average size of the pores is relatively in the order of a few microns. This results in very low permeability, although the bulk porosity could be higher than that of coarse grainstone.