Reservoir-scale structural heterogeneity, especially in terms of mechanical layering and natural fracture systems, is often insufficiently constrained by subsurface data alone. In North Oman, a large dataset in Cretaceous carbonates comprises data from multiple subsurface reservoirs and analogue outcrops. This provides an ideal opportunity to integrate outcrop constraints into the subsurface, and to calibrate the resulting models dynamically. For this purpose, a reservoir-scale analogue outcrop fracture template was created for the Jebel Madmar anticline in the Oman Mountains foothills. The outcrop template provides improved conceptual and quantitative constraints on (i) fracture types and dimensions (e.g. of NE-trending fracture corridors), (ii) fracture heterogeneity, both aerially and stratigraphically, (iii) fracture properties (e.g. cementation evolution, variations due to preferential fault/fracture reactivation) and (iv) structural evolution and history of reactivation. Within a regionally consistent structural framework, the outcrop template has greatly assisted in the creation of geologically realistic models for one of the fractured carbonate reservoirs, complementing the subsurface dataset. Initial dynamic calibration indicates successful application of the outcrop template in that the spatial fracture heterogeneity was succesfuUy captured in the reservoir models and provides a history match to production data. The reduced range of possible fracture system geometries in turn has provided better constraints on the effective fracture properties.

As part of an ongoing drive to enhance oil recovery from several fractured carbonate reservoirs in Oman, Shell's Carbonate Development Team and Petroleum Development Oman have applied a workflow and research software package aimed at better characterizing the complex subsurface. The workflow comprises several steps, each one supported by a multidisciplinary research program, and implemented in an integrated software environment for application to field development and enhanced oil recovery projects. The software tool, which interacts with the existing Static and Dynamic modeling packages, produces integrated reservoir models including fracture specific information. The capabilities include:Data integration and visualizationConstraints definition (from subsurface, analogue outcrops, geomechanics, etc.)3D fracture modeling (4) Link to reservoir simulation. The tool is flexible, such that any type of well data (Static and Dynamic), seismic data (attributes and interpretations), and constraints can be brought together in a single display. An analysis package allows rapid visual and interactive structural analysis to be made, with quantification of structural elements. Constraints are derived from outcrop and subsurface field examples, geomechanical data and sandbox analogue experiments. A key constraint includes mechanical layering as a control on fracture geometries. Fracture networks are generated following the defined constraints combining statistics and mechanical rules. The fracture network properties useful for the Dynamic simulation can be quickly extracted. Because emphasis is placed on characterization and maximum use of the relevant constraints, the tool helps ensuring that the fracture modeling time is spent on understanding and assessing the uncertainties. To date this workflow has been applied to several fields worldwide, demonstrating its suitability to address problems related to Natural Depletion, Waterflooding or Assisted Steam Gas Oil Gravity Drainage. Introduction Over the past few years one aspect of research within Shell's Carbonate Development Team has focused on gathering information on the key elements of natural fracture systems. In the Gulf Region, work was primarily carried out in the Zagros Mountains1 and in the Oman Mountain Foothills2. The main objectives of these studies are to provide enhanced constraints on fracture modeling in the subsurface. Important aspects of fracture systems that are typically poorly constrained by subsurface data alone are:accurate 2D and 3D characterization of structural objects, especially fracture corridors and the internal geometries of fault zones,the organization of multi-scaled fracture systems within mechanically layered rocks (i.e. the vertical extents of fractures intersected by wells), andthe internal flow properties of the fractures. In parallel a number of reservoir studies are being carried out, for example in the northern Oman region by Petroleum Development Oman (Figs. 1), providing an excellent opportunity to link the observations made at the surface with the complete reservoir data sets of the subsurface. The current research builds on the understanding of the regional structural framework and evolution of North Oman (Fig. 2) from previous studies2–10.

This paper presents an innovative integrated workflow applied to the characterization of a carbonate fractured reservoir in order to generate an effective 3D Matrix Block Size (MBS) distribution based on all available data: geological, geophysical and dynamic production data. The MBS is a key factor determining heating and thereby recovery efficiency during steam flooding in a fractured reservoir. The MBS model allows simulating the complex flow and establishing reservoir management strategies that will optimize oil recovery and facility sizing. The major difficulty in developing a 3D MBS model is the ability to account for the all the information pertinent to natural fractures in the field and develop an understanding of what geological characteristics are linked to the occurrence of fractures. Until recently most fractured reservoir modeling tools were limited to simple discrete statistical models. A new approach in fractured reservoir characterization, using primarily artificial intelligence tools, is presented in this paper. The methodology is based on the assumption that there is a complex relationship between a large number of potential geologic drivers (structure, faults, matrix characteristics etc.) and fractures. The combination of both the continuum fracture modeling (CFM) and discrete fracture network (DFN) modeling provides a quantitative framework for MBS distribution estimation, geological concepts and data integration. The application of this integrated workflow to the Qarn Alam field is presented in this paper. Introduction The Qarn Alam Field of Central Oman contains an estimated STOIIP of 185 million m3 of heavy oil, which is planned to be developed with a full-field steam injection EOR project. Despite the fact that the oil production from the main reservoir, the Shuaiba, is known to occur via a fracture/karst network, the vast majority of the oil is stored in the matrix. The porosity and permeability network of the matrix is often a function of the distribution of depositional rock facies. If significantly different facies are present in a reservoir, their spatial arrangement has to be understood and modeled adequately, in order to understand hydrocarbon distribution and recovery. Critical for the success of a full field steam injection EOR project is a proper understanding of the subsurface geology, most importantly the distribution of matrix porosity and permeability and the occurrence and distribution of hydraulically conductive fractures. This paper illustrates the combination of CFM and DFN modeling to model the fracture distribution and the MBS distribution.