The Barremian–Aptian upper Khami Group and Albian–Campanian Bangestan Group have been studied at outcrop in Lurestan, SW Iran. The upper Khami Group comprises a thin deltaic wedge (Gadvan Fm) transgressively overlain by shelfal carbonates (Dariyan Fm). The Dariyan Fm can be divided into lower and upper units separated by a major intra-Aptian fracture-controlled karst. The top of the Daryian Fm is capped by the Arabian plate-wide Aptian–Albian unconformity. The overlying Bangestan Group includes the Kazhdumi, Sarvak, Surgah and Ilam formations. The Kazhdumi Fm represents a mixed carbonate-clastic intrashelf basin succession, and passes laterally (towards the NE) into a low-angle Orbitolina-dominated muddy carbonate ramp/shoal (Mauddud Mbr). The Mauddud Mbr is capped by an angular unconformity and karst of latest Albian–earliest Cenomanian age. The overlying Sarvak Fm comprises both low-angle ramp and steeper dipping (5–10°) carbonate shelf/platform systems. Three regionally extensive karst surfaces are developed in the latest Cenomanian–Turonian interval of the Sarvak Fm, and are interpreted to be related to flexure of the Arabian plate margin due to the initiation of intra-oceanic deformation. The Surgah and Ilam Fm represent clastic and muddy carbonate ramp depositional systems respectively.Both The Khami and Bangestan groups have been affected by spectacularly exposed fracture-controlled dolomitization. Dolomite bodies are 100 m to several km in width, have plume-like geometry, with both fracture (fault/joint) and gradational diagenetic contacts with undolomitized country rock. Sheets of dolomite extend away from dolomite bodies along steeply dipping fault/joint zones, and as strata-bound bodies preferentially following specific depositional/diagenetic facies or stratal surfaces. There is a close link between primary depositional architecture/facies and secondary dolomitization. Vertical barriers to dolomitization are low permeability mudstones, below which dolomitizing fluids moved laterally. Where these barriers are cut by faults and fracture corridors, dolomitization can be observed to have advanced upwards, indicating that faults and joints were fluid migration conduits.Comparisons to Jurassic–Cenozoic dolomites elsewhere in Iran, Palaeozoic dolomites of North America and Neogene dolomites of the Gulf of Suez indicate striking textural, paragenetic and outcrop-scale similarities. These data imply a common fracture-controlled dolomitization process is applicable regardless of tectonic setting (compressional, transtensional and extensional).

Well-exposed outcrops of Middle Cretaceous carbonates in the Zagros fold belt, Iran have been used to provide input data for a dual porosity reservoir model incorporating both matrix and fracture heterogeneity. The modelled outcrop area is located on the steeper dipping limb of a large-scale (10km wide, 100km long) asymmetric Tertiary anticline. The outcrop is structurally and stratigraphically analogous to producing and prospective anticlines in the nearby subsurface. Matrix heterogeneity can be divided into primary (depositional) and secondary (diagenetic) heterogeneity. Sources of primary heterogeneity include: 1)large-scale depositional architecture (e.g. shelf margin clinoforms, depositional sequence architecture), 2) macrofacies architecture and distribution, e.g. length scale distribution and geometry of carbonate sand shoals and rudist biostromes, 3)microfacies distribution and associated variability in primary pore types. Sources of secondary heterogeneity include diagenetic alteration of primary pore systems, karstification and hydrothermal dolomitisation. We demonstrate a close link between primary heterogeneity and secondary porosity-permeability distribution in the matrix. To construct the outcrop model, vertical stratigraphic logging and sampling were undertaken to establish a synthetic well log from which reservoir architecture, zonation, facies, microfacies, pore-type, and porosity-permeability data could be derived. "Walking-out" of depositional and diagenetic elements captured horizontal and vertical correlation length scales of porosity-permeability distribution and architectural features. The main fractures present are normal faults and joints. Faulting was characterized using measurements of fault kinematics, orientation, displacement, length, fault zone thickness and fault zone petrology. The normal faults are non-stratabound and have power-law scaling. Faults were stochastically simulated in a discrete fracture network and then scaled up to a reservoir simulation grid. Resulting porosity-permeability distributions are highly heterogeneous. Joints are stratabound and have an almost constant density within the same stratigraphic horizon, regardless of outcrop location (e.g. fold limb vs fold crest). In contrast, joint density varies greatly vertically according to lithology/facies. Joints were modelled using a simple parallel plate model approximation. Permeability due to joints is highly heterogeneous vertically, but laterally homogeneous. Construction of the outcrop model has been key to reducing uncertainty in geological interpretation and modelling of subsurface data, in particular with regard to characterization of porosity-permeability distribution and in interpretation of test data. The modelling workflow presented in this paper is directly relevant to producing and prospective fractured Middle Cretaceous carbonate reservoirs elsewhere in the Middle East and in Mexico. Introduction Building 3D carbonate reservoir models for flow simulation is a major challenge for the petroleum industry, primarily due to the occurrence within carbonates of a wide range of heterogeneities occurring at a wide range of scales. Sources of heterogeneity in carbonate reservoirs can be divided into 3 main categories:Primary (depositional) heterogeneitySecondary (diagenetic) heterogeneityStructural (fracture) heterogeneity When a carbonate reservoir is heavily fractured, the reservoir typically has dual porosity/permeability behaviour, and it becomes important to understand and capture the flow dynamics of both the matrix (which acts as the hydrocarbon storage unit) and the fractures (which act as the main permeability pathways draining the reservoir) when building the reservoir model.

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