Lars Inge Berge

Pore-to-Field Scale Modeling of WAG

The paper describes an integrated pore-to-field scale modeling method of multiphase flow in porous media. Although the method is general, we demonstrate its power and versatility by modeling a WAG process in the Etive formation in a North Sea oil field. The method aims at capturing the relevant flow physics at different scales. Pore scale physics (μm-scale) is accounted for through predictive pore scale modeling of relative permeability and capillary pressure. The computed rock curves (cm-scale) are used to populate detailed geological models with a plausible spatial distribution of constitutive relations. Effective flow properties at the heterogeneous facies scale (m-scale) are determined by a steady state upscaling technique. Finally, the effective flow properties are implemented in a field scale (km-scale) simulation model. The simulation results show that the effective flow properties describe the reservoir WAG performance fairly accurately without any adjustment through history matching.

SWAG injection on the Siri Field: An optimized injection system for less cost

Simultaneous Water And Gas (SWAG) injection has been implemented on the Siri Field on the Danish Continental Shelf and represents the first reported full field application of its kind in the North Sea. The associated produced gas is mixed with injection water at the wellhead, and injected as a two-phase mixture. The required total injection volume for voidage replacement is thus achieved with a simplified injection system, fewer wells and reduced gas recompression pressure requirements. Injection per well has typically been in the range 4,000-8,000 Sm 3 /day (25,000-50,000 bpd) water and 200,000 - 400,000 Sm 3 /day (7-14 Mscf/d) gas. Evaluation of alternative injection schemes identified SWAG as the optimum scenario for Siri. The choice reflects that: a) There is no established gas export infrastructure in the immediate area, Siri gas volumes alone are too small to warrant establishment of a system, and routine gas flaring is unacceptable. Reinjection is therefore required. b) Reservoir simulation studies indicate improved oil recovery (IOR) with combined gas and water injection as compared to pure water injection, apparently related to attic oil displacement, reduced residual oil saturation and better sweep efficiency. c) Continuous water injection from both injectors is required to maintain reservoir pressure. The SWAG concept fulfills all these requirements, representing a safe, economic and environmentally-friendly development solution.

Micro-CT Facility for Imaging Reservoir Rocks at Pore Scales

A micro-CT facility for imaging, visualizing and calculating sedimentary rock properties in three dimensions (3D) is described. The facility is capable of acquiring 3D Xray CT images made up of 2000 voxels on core plugs up to 5 cm diameter with resolutions down to 2 μm. This allows the 3D pore-space of a rock to be imaged across several orders of magnitude. In parallel with standard microscopic techniques, the spatial distributions of different mineralogies can be identified. We demonstrate the capabilities by imaging a reservoir carbonate core at different resolutions. First, an image of a 4 cm diameter plug is analysed at a resolution of 42 μm. This allows one to deduce the size, shape and spatial distribution of the disconnected vug porosity. Within the imaged volume over 30000 separate vugs are identified and a broad vug size distribution is measured. From higher resolution images (2.5-20 μm) on a 5 mm diameter subset of the core one can measure characteristic (intergranular) pore sizes. The apparent porosity of the core increases with enhanced image resolution. This behaviour implies a continuum of pore sizes exist within the core at these resolutions. Carbonate sediments have been conventionally described by a discrete bior tri-modal pore size distribution; in contrast our analysis exhibits no distinct pore sizes but a broad distribution of pore size spanning over more than two orders of magnitude.

Continuum-based rock model of a reservoir dolostone with four orders of magnitude in pore sizes

A continuum-based pore-scale representation of a dolomite reservoir rock is presented, containing several orders of magnitude in pore sizes within a single rock model. The macroscale rock fabric from a low-resolution x-ray microtomogram was combined with microscale information gathered from high-resolution two-dimensional electron microscope images. The low-resolution x-ray microtomogram was segmented into six separate rock phases in terms of mineralogy, matrix appearances, and open- versus crystal-filled molds. These large-scale rock phases were decorated (modeled) with geometric objects, such as different dolomite crystal types and anhydrite, according to the high-resolution information gathered from the electron microscope images. This procedure resulted in an approximate three-dimensional representation of the diagenetically transformed rock sample with respect to dolomite crystal sizes, porosity, appearance, and volume of different matrix phases and pore/matrix/cement ratio. The resulting rock model contains a pore-size distribution ranging from moldic macropores (several hundred micrometers in diameter) down to mudstone micropores (1 m in diameter). This allows us to study the effect and contribution of different pore classes to the petrophysical properties of the rock. Higher resolution x-ray tomographs of the same rock were used as control volumes for the pore-size distribution of the model. The pore-size analysis and percolation tests performed in three dimensions at various discretization resolutions indicate pore-throat radii of 1.5 to 6 m for the largest interconnected pore network. This also highlights the challenge to determine appropriate resolutions for x-ray imaging when the exact rock microstructure is not known.