The determination of petrophysical properties in carbonate rocks is strongly affected by depositional heterogeneity at different scales, complex mineralogy, and diagenetic modification. Superimposed complex depositional and diagenetic processes typical in carbonates lead to a very wide range of pore sizes involving many orders of magnitude of length scales. Pore types are a primary control on fluid movement in the reservoir and constitute the primary variable in determining petrophysical rock types. Multimodal pore systems and irregular water distribution across the field caused by complex charging history present challenges in water saturation modeling using conventional saturation-height functions. Bitumen quantification presents another challenge in carbonate reservoirs, especially in fields without nuclear magnetic resonance logs. Fractured reservoirs entail uncertainties related to characterization, modeling, and enhanced oil recovery aspects that involve matrix oil recovery via higher permeability fracture networks.
These challenges exist in Tengiz Field, a Paleozoic isolated carbonate platform reservoir in the Precaspian Basin in Kazakhstan - one of the world's deepest and most prolific supergiant fields with more than 25 billion barrels original oil in place. The buildup includes: productive platform-top settings composed of grainstone and packstone with an average porosity of 8%; and fractured margin and slope environments predominantly consisting of boundstone, breccia, and grain-dominated deposits with an average porosity of 4%. Tengiz exhibits primary stratigraphic and depositional heterogeneity and has an extensive and complex diagenetic history that greatly modified original pore systems and affected present-day reservoir quality. This paper describes how the above challenges were addressed in petrophysical characterization of Tengiz field. The solutions include special core and log acquisition programs, bitumen modeling with Multimin calibrated with TOC data, comprehensive rock typing, hybrid water saturation modeling using porebased saturation-height functions and bulk volume water approach, total permeability from production logs, baffles identification from pressure gradients, and integrated fracture characterization.