The Clair oilfield is a large fractured sandstone reservoir lying 75 km west of Shetland on the UK continental shelf. Fracture analysis and modelling was carried out in preparation for the phase 1 development, which started production early in 2005. Fracture clusters and discrete fluid inflows observed in wells are associated with faults and other localized deformation features tens or hundreds of metres apart. The reservoir has moderate to good matrix permeability, but well flow rates and profiles are fracture-dominated. Full-field geological models were built using conventional object modelling approaches for matrix and discrete fracture networks for fractures, and upscaled to populate a reservoir simulation grid. Dual-porosity, dual-permeability dynamic modelling (full-field and well-test) was undertaken to understand the fracture and matrix flow contributions and their interaction. Fracture models were conditioned to wells and to seismic data, including coherency and multi-azimuthal velocity information from a four-component, ocean bottom cable three-dimensional seismic survey. At this early stage in field development, there is insufficient calibration to select a single fracture model. Instead, well and depletion plans have been tested against multiple fracture models chosen to encompass a wide range of plausible outcomes.
The Clair oilfield was discovered in 1977 and began production in 2005. It is a heterogeneous fractured sandstone reservoir with an estimated STOIIP of c. 1.5 billion barrels in the Phase 1 development area. An extended appraisal programme was required to assess reservoir deliverability, which is controlled by the distribution of natural fractures. Development drilling increased the understanding of the fracture system, through acquisition of conventional core, open-hole logging, drilling mud-loss recording, production logging and well test transient analysis. These data revealed a complex fracture system of conductive faults and background joints. Post-production formation pressure measurements showed greater lateral and vertical connectivity than would be expected from matrix and fluid properties alone. However, large pressure differences were encountered close to or across features mappable at a seismic scale. Closed fractures or sealing faults can form baffles between compartments, and conductive faults or fractures allow rapid pressure communication. In some cases the connection path or barrier can be identified with seismically mapped features. When the field was put onto water injection, one year after start-up, a key concern was the degree of imbibition of water from the fractures to the matrix. Despite the observed pressure connectivity, water breakthrough did not take place until 2007. Most producers have completions designed to permit zonal water shut-off. A successful intervention was carried out in early 2008, after a production logging run had demonstrated water entry at the toe of a high-angle well. The crestal Core segment of the development benefits from a permanent 4D seismic array of ocean-bottom cables. In 2007 the first permanent monitor survey was acquired and processing gave indications of a 4D response. These 4D data are improving the dynamic reservoir understanding and providing valuable spatial context to the well results.
Pressure depletion during production from a reservoir can cause geomechanical changes in both the reservoir and overburden. Dropping the pore pressure in the reservoir increases the load on the rock matrix, resulting in compaction. In most cases, the magnitude of this compaction is negligible; however, when depletion pressures are large or when the reservoir rock is highly compressible, the compaction may be significant. As the reservoir pulls away from the surface of the earth, a stress arch forms in the overburden, with the vertical stress decreasing directly above the reservoir and increasing in the pillars of the stress arch. These stress changes can perturb the seismic velocities, which, combined with the changes in path length to the reservoir, can cause traveltime changes in the overburden. The unloading of the overburden directly above the reservoir shields the reservoir from seeing the full change in pore-fluid pressures and thus can have a significant impact on the amplitude changes in the reservoir between repeat seismic surveys. We describe a workflow for rapidly modeling these geomechanical changes and their associated seismic signatures. Using a set of simple synthetic reservoir models, we demonstrate the impact of reservoir aspect ratio (thickness to diameter ratio) and dip on the magnitude of the stress arch. Finally, we present a case study from the Gulf of Mexico that demonstrates the importance of including geomechanical changes in 4D modeling and interpretation.
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