Chemical Compaction as the Driving Mechanism for Reservoir Quality Variation in an Early Cretaceous Middle Eastern Carbonate Reservoir.
Authors: Sellar Christopher , Vrsic Ales , Contreras David , Raithatha Bansri 
Published: November 2020

Reservoir 2 shows the same vertical facies stacking pattern across Oilfield A. These facies are observed to be laterally continuous across other oilfields in Abu Dhabi. Multi-scale static and dynamic data show a north to south degradation in reservoir quality across the field. A petrographic, core and borehole image-based evaluation has generated a robust geological concept governing porosity and permeability distribution across Reservoir 2 that is calibrated to seismic impedance and dynamic data.

Diagenetic phases were quantified and mapped as part of a detailed sedimentological and petrographic description of Reservoir 2. Samples were analysed for stable isotopes and fluid inclusion microscopy. Chemical compaction features were described in detail in high quality cores. The cored intervals feature abundant preserved samples with up to 30% of the cored interval unavailable for reservoir characterization due to preservation. Consequently, a detailed borehole image description was undertaken and utilized to describe the structural features at log scale and fill in the missing core sample gaps.

Petrographic description and mapping shows calcite cement occludes almost all macroporosity in the south of Reservoir 2. The abundance of cement decreases towards the north. Core and BHI based descriptions of chemical compaction features show a higher abundance of stylolites in the south Reservoir 2 than in the north. Most of the primary fluid inclusions trapped within calcite cements are monophase, potential evidence that pore-filling calcite started to precipitate under cooler burial conditions, at temperatures between 60-70°C. It is proposed that stylolitisation is contemporaneous with cementation where carbonate material dissolved during chemical compaction formed the main source for cement precipitation. Reservoir 2 is up to 10% thinner in the south of Oilfield A than in the north. Increased chemical compaction in the south is correlated with decreased reservoir thickness. There is a strong correlation between the pattern of reservoir thickness and P-impedance from seismic inversion. P-impedance is negatively correlated to porosity. Stylolites are most common in reservoir intervals 2A and 2B. These intervals display a wide range of porosity and permeability from north to south, while in contrast reservoir interval 2C, with very few stylolites, has a narrow range of porosity and permeability variation field wide.

It is proposed that chemical compaction is the key driver for degrading reservoir quality in Reservoir 2. All scales of static and dynamic data have been reconciled to show that chemical compaction, cementation and reservoir quality are intimately related processes. The implications for producer and injector well design are significant. Depending on the location of the planned well and the development interval to be drilled, well spacing and reservoir contact should vary accordingly, while maintaining the optimal field development pattern.