The impact of hydrocarbon emplacement on carbonate cementation

Abstract

Carbonate reservoirs are porous and permeable sedimentary rocks, mainly in the form of limestones and dolostones that are composed of CO3 2-group-forming minerals. They currently account for about 60% of the world’s remaining hydrocarbon resources and are now future targets for hydrothermal energy exploitation, CO2, hydrogen and waste storage. Good or excellent carbonate reservoirs have porosities and permeabilities within the range of 15-20% and 100 to 500 mD respectively. These properties and their distribution are of utmost importance in the exploration of subsurface resources and waste storage but are largely affected by the level of cementation. Cementation is the precipitation and growth of inorganic minerals in the pore spaces of rocks and forms the most important factor for porosity and permeability destruction in carbonate reservoirs. This process of cementation has been reported to be affected by the presence of hydrocarbons, however, the exact nature of the relationship between the presence of hydrocarbon and the rates and volumes of cementation isn’t well defined. This thesis is, therefore, focused on understanding the dynamics of oil presence in cementation, but with a particular interest on calcite cementation to begin with, via an experimental approach. The goal is to develop a process-based pore-scale model, which will quantify the direct role of oil in the cementation process, for predicting reservoir quality distribution. To achieve this, the calcite cementation experiments were carefully designed and initiated both in the presence and absence of oil, to represent the oil and water legs of petroleum reservoirs respectively. This was done both in an open system and porous media, via a reactive transport mechanism involving 5 phases (rock grains, brine, cement, oil and air) at room conditions. Micro Computer tomographic scan (ⴗ-CT scan) was used to acquire images from the porous media experiment for image segmentation and separation, using a range of digital processing tools for phase quantification and interpretation. Scanning electron microscopy (SEM) and x-ray diffractometry (XRDF) were used to determine the nature, dynamics and mineralogy of the resulting calcite precipitate respectively. Brine composition before, during and after experiments was analysed by inductively coupled plasma mass spectrometry (ICP-MS) to infer the rate of calcite precipitation during the experiments. Fourier-transform infrared spectroscopy (FTIR), Thermographic analysis (TGA), Energy dispersive x-ray spectroscopy (EDX), dye and floatation tests were used to investigate the surface properties of the rock grains in the system. The result establishes that even the early timing of hydrocarbon emplacement does not stop cementation, but can slow down its rate or level, reduce the texture of the cement and affect its localisation within the pores of the reservoir. This impact is more enhanced in oil-wet reservoirs and varies directly with oil saturation and is also dependent on the wettability and mineral saturation of the brine. In the presence of even a small amount of oil, even as little as 6% oil saturation, cementation can be significantly reduced.