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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAn intensely fractured reservoir in central Oman is being developed by injecting steam into the crest of the field, heating the oil in the matrix and producing it via a Gas-Oil Gravity Drainage (GOGD) process. Both the static and the dynamic data support a strongly fractured (and leached) reservoir. Building 3D full field fracture models that capture the possible scenarios proved to be a challenge, largely because to date (i) most wells in the crest are vertical, (ii) a limited number of horizontal wells have been drilled on the flanks, (iii) seismic quality is relatively poor, and (iv) dynamic constraints on the permeability structure are limited, especially on the flanks. A new 3D fracture software tool (SVS) has been used to maximize the value of fracture-related reservoir data through improved integration, visualization, analysis and correlation. Rapid interactive analysis of the data set allows the user to efficiently characterize and understand the nature of the fracture system and its relationships to other reservoir parameters. The data analysis indicates that two end member fracture system scenarios could be present in the reservoir i) a mechanical stratigraphy related and ii) fault/corridor related fracture system. This is particularly true of the flank wells, which despite being mostly located away from the main seismic scale faults on the crest, have evidence for fault related fracture clusters at intervals down the well bore. For these end member, and intermediate scenarios, "Low", "Medium" and "High" Case models were created using fracture trend maps/grids that combine the data and a range of geological constraints. More remote information was included from outcrop fault patterns in northern Oman. A combination of detailed process based discrete fracture generation and rapid fracture attribute generation was used to populate over 15 full field simulation grids capturing the range of remaining uncertainty of the fracture system across the field.

TA-GOGD is thermally assisted gas-oil gravity drainage suited for heavy oil in highly fractured formations. Steam is injected into the fractures to serve two purposes: to apply a gas gradient across the matrix blocks so that the oil in the matrix drops down by gravity and to heat the carbonate matrix blocks so that the reduced viscosity oil drips out faster. The reservoir has two fluid systems, which are gas/oil/water levels in the fractures and gas/oil/water contacts in the matrix blocks that are separated by the fractures. Reservoir surveillance requires logs of the remaining oil saturation to confirm the recovery, which is dependent upon the heterogeneities of fracture intensity and vertical permeability. The changing fluid saturations in the matrix are primarily oil replaced by hydrocarbon gas, but six fluids could be present and change: methane and steam, hot low-viscosity and cold high-viscosity oil, formation water, and condensed steam. The important zone is above the fracture gas/oil contact, where drained oil is replaced by the secondary gas cap or steam. Time-lapse pulsed neutron capture logs during the pilot phase did not provide the required matrix fluid saturations due to interference from variable annular fluids in the poorly cemented casing that masked the reservoir response. There is no logging tool available that is capable of measuring the matrix oil saturation change without being influenced by the other fluids in the matrix or the fracture-controlled fluid levels in the casing annulus, or characterized for an open gas-filled borehole, and built to withstand 247°C. The physics of nuclear magnetic resonance (NMR) provides the best chance to fulfill this reservoir surveillance requirement. This paper recounts the decision process that preceded this conclusion, and suggests a method of building a high-temperature non-metallic and non¬magnetic flask to facilitate NMR time-lapse logging in dedicated openhole observation wells in TA-GOGD developments.

The "A" East Haradh formation contains a 200 m thick oil column of highly viscous oil, with viscosity ranging from 200 to 400,000 cp. Due to the high viscosity, first production was considered only possible using thermal EOR techniques, starting with Cyclic Steam Stimulation (CSS). The field has now been in operation for more than two years, with a number of wells already into a third CSS cycle. This paper will focus on the key learnings derived during this initial operations phase of CSS in "A" East Field including, amongst others, key trial results on different well completions and artificial lift systems combined with new insight into the reservoir architecture. In addition, reservoir performance management is being streamlined through the development of a structured approach to the CSS planning and using dedicated visualisation. Automated Exception Based Surveillance "triggers" are currently being developed to efficiently address any deviation from the operating envelopes and further optimise the recovery from this 81 well CSS development. Based on the very encouraging performance to date, the company has already sanctioned a further 34 well CSS expansion of the current development with drilling scheduled to commence in 2016.