Porosity and permeability of tight carbonate reservoir rocks in the north of Iraq

• The Kometan can be divided into 3 lithological units.
• Three types of petrofacies have been identified; all affected by diagenesis.
• Petrofacies A is low porosity and permeability indicating low reservoir quality.
• The 2 other petrofacies have undergone dissolution and are good reservoir quality.
• Petrofacies A: stylolites reduce reservoir quality while fracture enhanced it.

The distribution of reservoir quality in tight carbonates depends primarily upon how diagenetic processes have modified the rock microstructure, leading to significant heterogeneity and anisotropy. The size and connectivity of the pore network may be enhanced by dissolution or reduced by cementation and compaction. In this paper we have examined the factors which affect the distribution of porosity, permeability and reservoir quality in the Turonian–Campanian Kometan Formation, which is a prospective low permeability carbonate reservoir rock in northern Iraq. Our data includes regional stratigraphy, outcrop sections, well logs and core material from 8 wells as well as a large suite of laboratory petrophysical measurements. These data have allowed us to classify the Kometan Formation into three lithological units, two microfacies and three petrofacies. Petrofacies A is characterized by dense and compacted and cemented wackstone/packstone with nanometer size intercrystalline pores and stylolites and presents a poor reservoir quality (porosity range 0.005±0.01 to 0.099±0.01, permeability range 65 nD–51 μD). Occasional open fractures in Petrofacies A improve reservoir quality resulting in a 2–3 order of magnitude increase in permeability (up to 9.75 mD). Petrofacies B is a dissolved wackstone/packstone that contains moldic and vuggy pores (porosity range 0.197±0.01 to 0.293±0.01; permeability range 0.087–4.1 mD), with both presenting good reservoir quality, while Petrofacies C is a carbonate mudstone that has undergone dissolution and possibly some dolomitization (porosity range 0.123±0.01 to 0.255±0.01; permeability range 0.065–5 mD). All three petrofacies can be distinguished from wireline log data using porosity and NMR measurements. A poroperm plot of all of the data is fitted by a power law of the form k(mD)=aϕb with a=28.044 and b=2.6504 with coefficient of determination, R2=0.703. When the permeability is predicted with the RGPZ model of the form k(mD)=d2ϕ3m/4am2 with mean grain diameter d=10 μm, and mean cementation exponent m=1.5 and a=8/3 a better fit is possible with R2=0.82.

Porosity-Permeability relationships for all samples.Figure optionsDownload as PowerPoint slide