Flow Through Inhomogeneous Fault Zones
- Harald H. Soleng (Norwegian Computing Center) | Anne Randi Syversveen (Norwegian Computing Center) | Arne Skorstad (Norwegian Computing Center) | Per Roe (Norwegian Computing Center) | Jan Tveranger (Centre for Integrated Petroleum Research)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 11-14 November, Anaheim, California, U.S.A.
- Publication Date
- Document Type
- Conference Paper
- 2007. Society of Petroleum Engineers
- 7.2.2 Risk Management Systems, 4.3.4 Scale, 5.5.3 Scaling Methods, 1.6.9 Coring, Fishing, 5.2 Reservoir Fluid Dynamics, 1.2.3 Rock properties, 4.1.5 Processing Equipment, 5.5 Reservoir Simulation, 2.4.3 Sand/Solids Control, 4.1.2 Separation and Treating, 5.1.2 Faults and Fracture Characterisation, 1.10 Drilling Equipment, 5.1.5 Geologic Modeling
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Faults significantly influence fluid flow in reservoirs. In standard reservoir flow-simulator grids, faults are represented as surfaces or planes. However, outcrop studies show that faults often must be regarded as volumetric elements. Inside such fault zones, the facies characteristics differ significantly from those in the rest of the reservoir. In a fault facies reservoir model faults are represented as volumes populated with facies with properties derived from their origin and faulting history.
In this paper, we compare fluid flow performance of a fault facies model and a conventional fault model. The uncertainties attached to the fault zone properties and architecture included in the fault facies model produce a straightforward effect on the range of simulation outcomes and uncertainty of production parameters. In the conventional model, similar effects can only be reproduced ad hoc using poorly determined random fudge factors. We also look at the effect of upscaling the fault zone. Results show that the flow properties in the fault facies model differ from the conventional model with regard to both water cut and total oil production. As expected, upscaling may introduce a significant bias in the cumulative oil production.
Faults most commonly act as barriers for fluid flow, but sometimes they act as conduits. In order to perform reliable forecasting of production performance, it is crucial to understand the causes for this contrasting behavior, and capture them properly in the reservoir model.
Faults normally occupy a negligible fraction of the total volume of a petroleum reservoir, and fault thicknesses are commonly significantly smaller than cell dimensions used in reservoir models. It may therefore seem natural to model faults as membrane-like two-dimensional slip surfaces. Faults display different sealing properties. This is chiefly due to contrasting or varying host rock properties, displacement magnitudes and tectonic development. In conventional flow models, transmissibility multipliers represent the fault sealing effects. Non-neighboring connections take care of flow along the slip plane.
Industry-standard flow simulators translate all permeabilities into transmissibilities. Hence, any permeability field could just as well be represented as a transmissibility field. From this perspective, the traditional fault model is fully adequate.
In reality, a fault zone is a complex three-dimensional object where host rock facies from different zones are mixed and transformed into new, tectonized facies types. It is clear that without a proper stochastic model based on the physics of faults, it is impossible to determine and quantify the uncertainty of all its flow properties. The fault facies model1 addresses this problem by advocating detailed modeling of fault zones.
The present paper compares impact on modeled reservoir fluid flow of the two modeling approaches by using a synthetic model of multi-phase oil reservoir with one water injector well and one oil production well separated by a single large fault.
In this paper we consider a synthetic reservoir containing high permeable sand bodies in a background of shale with a fault with varying displacement cutting through the whole region. Two classes of models are constructed. One is a conventional fault model where the fault is represented by a two-dimensional slip surface with non-neighbor connections and transmissibility multipliers. The other is a fault facies model where the fault zone is subject to detailed geostatistical modeling. We keep the petrophysics outside the fault zone equal in all realizations of both classes.
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