Interactive Reservoir Simulation

Regtien, Jeroen M.M.; Por, G.J.A.; Stiphout, M.T. van; Vlugt, Frans F. van der

doi:10.2118/29146-ms

Cited by 44 publications

(11 citation statements)

References 3 publications

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“…The simulations were conducted with the Shell proprietary reservoir simulator MoReS (Regtien et al, 1995), which is a fully implicit finite volume Darcy flow simulator. A porous media representative for Berea sandstone with a porosity of 25% and permeability K = 100 ± 2 mD was considered.…”

Section: Comparison To Numerical Simulationsmentioning

confidence: 99%

Stability of CO2–brine immiscible displacement

Berg

Ott

2012

International Journal of Greenhouse Gas Control

126

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a b s t r a c tThe viscous stability of the primary drainage process is of major interest for the injection of carbon dioxide (CO 2 ) in saline aquifers, since it determines the spread of the CO 2 plume in the target aquifer and consequently the initial utilization of the pore space for CO 2 storage. In order to analyze the stability of the displacement process, the relative permeability saturation functions must be known; these are usually derived by experiments under conditions representative for the field. It is therefore very important to characterize the flood front stability, not only on the field scale but also on the experimental scale, in order to judge the validity of the experimental results as a precondition for reliable field simulations.Here we investigate the onset of viscous fingering, thereby studying under what conditions CO 2 -brine displacement remains stable. We discuss the role of relative permeability and the stabilizing effect of capillary pressure at different length scales by means of numerical simulations. The results allow us to assess different definitions of the mobility ratio and establish criteria for judging the stability of the displacement process. We further show that in cases where gravitational forces are important, the gravity tongue dominates the fingering pattern, and unstable situations can occur where stability would be predicted, by considering viscous and capillary forces only.In the literature various criteria for the onset of instability have been proposed, but these are inconsistent or inconclusive. Our intention is to bring order into this discussion. In the present study we validate or refute stability criteria by numerical modeling and show that the shock-front mobility ratio correctly describes the onset of fingering. The application of our findings is not limited to CO 2 -brine displacement. The criteria for stability can be applied to most two-phase flow problems in reservoir engineering in general ranging from water flooding to low interfacial tension surfactant flooding.

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Section: Comparison To Numerical Simulationsmentioning

confidence: 99%

Stability of CO2–brine immiscible displacement

Berg

Ott

2012

International Journal of Greenhouse Gas Control

126

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“…MoReS was the first fully interactive multi-platform reservoir simulator [3], with a flexible scripting interface, a modular object oriented design for black-oil, equation-of-state (EOS), and K-value compositional simulations. It has been used extensively for conventional and enhanced oil-recovery projects, and usually in conjunction with modeling experimental and field data (cf.…”

Section: Model Descriptions Simulation Requirements and Simulatormentioning

confidence: 99%

Estimate CO2 storage capacity of the Johansen formation: numerical investigations beyond the benchmarking exercise

Wei

Saaf

2009

Comput Geosci

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In this paper, Shell's in-house reservoir simulator MoReS is applied to a recently introduced CO 2 sequestration benchmark problem entitled "Estimation of the CO 2 Storage Capacity of a Geological Formation" (Class et al. 2008). The principal objective of this benchmark is the simulation of CO 2 distribution within a modeling region, and leakage of CO 2 outside of it, for a period of 50 years. This study goes beyond the benchmarking exercise to investigate additional factors with direct relevance to CO 2 storage capacity estimations: water and gas relative permeabilities, permeability anisotropy, presence of sub-seismic features (conductive fractures, thin shale layers), regional hydrodynamic gradient, CO 2 -enriched brine convection (due to brine density differences), and injection rates. The effects of hydrodynamic gradients and gravitationally induced convection only become significant over 100 s of years. This study has thus extended simulation time to 1,000 years. It is shown that grid resolution significantly impacts results. Vertical-grid refinement results in larger and thinner CO 2 plumes. Lateral-grid refinement delays leakage out of the model domain and reduces injection pressure for a given injection rate. Sub-seismic geological features such as fractures/faults and shale layers are demonstrated to have impact on

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“…Multiphase flow is simulated using an in-house reservoir simulator -Modular Reservoir Simulator (MoReS) (Regtien et al, 1995). The flow model (labeled as model 1) is a box-shaped oil-bearing reservoir sandwiched between a shale and an active aquifer, with dimensions of 100 × 200 × 42.5 m 3 .…”

Section: Water Front Monitoring Using Borehole Radar Flow Modelingmentioning

confidence: 99%

Reservoir monitoring using borehole radars to improve oil recovery: Suggestions from 3D electromagnetic and fluid modeling

et al. 2018

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The recently developed smart well technology allows for sectionalized production control by means of downhole inflow control valves and monitoring devices. We consider borehole radars as permanently installed downhole sensors to monitor fluid evolution in reservoirs, and it provides the possibility to support a proactive control for smart well production. To investigate the potential of borehole radar on monitoring reservoirs, we establish a 3D numerical model by coupling electromagnetic propagation and multiphase flow modeling in a bottom-water drive reservoir environment. Simulation results indicate that time-lapse downhole radar measurements can capture the evolution of water and oil distributions in the proximity (order of meters) of a production well, and reservoir imaging with an array of downhole radars successfully reconstructs the profile of a flowing water front. With the information of reservoir dynamics, a proactive control procedure with smart well production is conducted. This method observably delays the water breakthrough and extends the water-free recovery period. To assess the potential benefits that borehole radar brings to hydrocarbon recovery, three production strategies are simulated in a thin oil rim reservoir scenario, i.e., a conventional well production, a reactive production, and a combined production supported by borehole radar monitoring. Relative to the reactive strategy, the combined strategy further reduces cumulative water production by 66.89%, 1.75%, and 0.45% whereas it increases cumulative oil production by 4.76%, 0.57%, and 0.31%, in the production periods of 1 year, 5 years, and 10 years, respectively. The quantitative comparisons reflect that the combined production strategy has the capability of accelerating oil production and suppressing water production, especially in the early stage of production. We suggest that borehole radar is a promising reservoir monitoring technology, and it has the potential to improve oil recovery efficiency.

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Interactive Reservoir Simulation

Cited by 44 publications

References 3 publications

Stability of CO2–brine immiscible displacement

Stability of CO2–brine immiscible displacement

Estimate CO2 storage capacity of the Johansen formation: numerical investigations beyond the benchmarking exercise

Reservoir monitoring using borehole radars to improve oil recovery: Suggestions from 3D electromagnetic and fluid modeling

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