Well performance is extremely variable in the stacked sequence of relatively tight Devonian and Mississippian carbonates in the northern part of the Waterton Complex, Alberta, Canada. This is despite having an extensively developed fracture system present in all the wells. In order to determine why some wells penetrated more permeable fractures than others, a full reinterpretation of the geophysical, structural, stress, matrix and dynamic data sets was carried out. Flow simulations at sector scales using discrete fracture network models and fullfield continuum modelling were used to test a range of geological and dynamic scenarios. One of the most northwestern fields of the Waterton complex, the West Carbondale field, is the focus of the work presented. For this field the best-fit dynamic models consist of a major fracture zone, corresponding to either a seismic scale lineament or zone of enhanced curvature, trending through the area of most prolific wells. Outside this zone, the vast majority of the fracture system makes little contribution to the flow in the wells, other than slightly enhancing the reservoir permeability.

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.

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Thermally Assisted Gas Oil Gravity Drainage of a fractured carbonate heavy oil field in Oman is starting the full field phase. Unlike a normal steam flood, steam is used as a heating agent to enhance the existing gravity drainage mechanisms. The project has been piloted successfully. The project start-up sequence consists of increasing off take from deviated producers followed by steam injection and aquifer pump-off. Steam will progressively fill the fractures whilst heated oil drains down in the matrix blocks and accumulates in an oil rim below the steam in the fractures. The fracture oil rim will be lowered by approximately 100m. Horizontal producers will be completed in the final fracture oil rim position. As no analogues exist a large degree of flexibility has been incorporated in the field development plan to cover uncertainties including caprock integrity, erratic oil rim movement and heterogeneous steam distribution. To facilitate decision making an enhanced reservoir surveillance, modelling and management system has been built. Reservoir pressures, oil rim positions, temperatures and rock strain data are obtained from a range of observation wells. Further data are obtained from surface uplift, microseismic monitoring and fluid sampling. Static, fracture, dynamic and geomechanical reservoir models have guided the design of the reservoir surveillance program and underlie the operating guidelines for the reservoir. These provide operator reactions for a wide range of "what-if" events. A corporate real time data portal has been optimised for the unique requirements of this project allowing for analysis of all data streams. A system allows 3D display, through time, of reservoir data and model forecasts to ensure optimum performance analysis. Initial application has resulted in identification of optimised well configurations and start-up sequence giving higher oil forecasts. The learning is being applied further in Oman and has wider application.

TA-GOGD is suited for heavy oil in fractured formations. Steam is injected into the fractures serving two purposes; applying a gas gradient across the carbonate blocks so that the oil in the carbonate drops down by gravity, and heating the carbonate blocks so that the reduced viscosity oil drips out faster. The reservoir has two fluid systems; gas/oil/water levels in the fractures, and gas/oil/water contacts in the carbonate. Oil extracted from the carbonate accumulates in the fractured oil rim, where it is produced by wells intersecting the fractures. It is essential to manage the oil rim position and thickness. Wireline interventions with gradio manometer are not safe where steam is injected at 55 bars and 271°C. This temperature is too hot for permanent electronic gauges, but is within the operating range of optic fiber used to measure distributed temperature.A new measurement to determine the fluid levels was developed using differential thermal relaxation. Cold water was pumped around a U tube containing an optic fiber and clamped outside the perforated tubing across the open hole until the temperature at the reservoir depth inside this U tube was considerably less than the hot surrounding gas, oil and water. With the pump stopped, the rate at which the cooler water inside this U tube reached thermal equilibrium with the warmer well bore fluids was measured with rapidly repeated distributed temperature surveys. Gas, oil and water have different specific heat capacities and thermal conductivities, so each surrounding fluid took a different length of time to heat the cooler water inside the U tube. The differences caused sharp discontinuities on the initial temperature logs of the warming water inside the U tube at the depths of the fluid contacts. The fluid levels measured with this method are sufficiently accurate to manage the oil rim.