Recent Advances in the Understanding and Incorporation of the Multiphase Fluid Flow Properties of Fault Rocks Into Production Simulation Models
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Abstract For many years it has been common practice to adjust fault transmissibility multipliers within production simulation models to achieve a history match without any scientific justification. In effect, this often means that faults are made ‘scapegoats’ to compensate for inadequacies in reservoir characterisation. In recent years it has become increasingly popular to calculate geologically-realistic transmissibility multipliers based upon measurements of absolute fault permeability and fault rock thickness. A key problem with this method is that it does not take into account the multiphase flow properties (relative permeability and capillary pressure) of fault rocks. This is hardly surprising as the multiphase flow properties of fault rocks are still largely unknown. Here we present measurements that show that under reservoir conditions cataclastic fault rocks may often have maximum gas relative permeabilities that are over two orders of magnitude lower than the undeformed reservoir sandstone adjacent to the fault. Incorporating the multiphase flow properties of faults into production simulation models is still challenging as their static and dynamic properties vary significantly compared with the undeformed reservoir. We review different existing methods for incorporating the multiphase flow properties into simulation models, and we recommend some possible approaches for treating faults that improve on the existing knowledge and software.Keywords:
Multiphase flow
Cataclastic rock
Relative permeability
Reservoir Simulation
Most carbonate reservoirs in Middle East are characterized as porous fractured reservoirs. Estimation of relative permeability of these highly heterogeneous reservoirs is challenging due to the existence of discontinuity in the fluid flow fractured porous media. Although relative permeability is an essential data for simulation of flow in fractured media, few attempts have so far been made to estimate the relative permeability curves. Most notable are the studies by Akin (J Pet Sci Eng 30(1)1–14, 2001), Al-sumaiti and Kazemi (2012), and Fahad (2013). This paper presents an integrated approach to history matching the oil drainage tests, which were carried out by unsteady state, on glass bed models with a single fracture at different orientations and to estimate the relative permeability curve. The integrated approach includes an inversion algorithm coupled with forward numerical modeling of fluid flow. The history matching of the displacement test data was obtained by using the Levenberg–Marquardt algorithm to minimize the error between the simulated and experimental data. In this algorithm, Corey-type power law is used to create relative permeability curves during the optimization procedures. The forward modeling is a 3D multiphase fluid simulator for flow through discrete fractures. Numerical results of fluid flow profiles and the optimized relative permeability curves for single fracture with different orientations and experimental validation with oil drainage tests are presented. The results of the optimized relative permeability data for single fracture are in a good agreement with the data derived by the correlation of Fahad (2013). These results prove that the presented approach can be used to upscale the relative permeability curve from laboratory scale to reservoir grid scale. The work on the upscaling of the estimated relative permeability curve of fractured porous media is under preparation and will be published soon.
Relative permeability
Reservoir Simulation
Poromechanics
Multiphase flow
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Relative permeability
Saturation (graph theory)
Multiphase flow
Petroleum reservoir
Reservoir Simulation
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Abstract Relative permeability ( k r ) and the capillary pressure ( P c ) are the central key elements defining the multiphase fluids flow behavior in the porous media. However, the dynamic capillarity should consider the dynamic relative permeability and the dynamic capillary pressure while performing waterflooding process in extremely low permeable formations. In order to improve the oil production, the advanced horizontal well drilling along with multiple hydraulic fracturing is generally instigated to penetrate the unconventional resources. The aim of this study is to consider the dynamic capillarity in a commercial reservoir simulation, while utilizing the data gained from the dynamic and steady experiments of the relative permeability and the capillary pressure impacts during waterflooding process in the core plugs of unconventional tight oil reservoirs. The commercial reservoir simulation conducted sensitivity analyses using Computer Modeling Group simulator. The outcomes show that the well production of the reservoir is overestimated while implementing steady data for forecasting due to which the oil saturation decreases more equally and further rapidly. Additionally, the forecast of the well production estimated to breakthrough sooner. However, neglecting the dynamic capillarity causes a huge breakthrough of water influx. Therefore, the core objective of this study is to probe the consequences of taking into consideration the dynamic capillarity in ultra-low permeable formations while giving an alternative perspective to forecast the production of the hydraulically fractured unconventional tight oil reservoirs.
Relative permeability
Capillary pressure
Reservoir Simulation
Multiphase flow
Saturation (graph theory)
Dynamic simulation
Tight oil
Directional Drilling
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