Numerical simulation of fluid-flow processes in a 3D high-resolution carbonate reservoir analogue

Agada, Simeon Sani; Chen, Fuzhen; Geiger, Sebastian; Toigulova, Gulnara; Agar, Susan M.; Shekhar, Ravi; Benson, Greg; Hehmeyer, Owen J.; Amour, Frédéric; Mutti, Maria; Christ, Nicolas; Immenhauser, Adrian

doi:10.1144/petgeo2012-096

Cited by 30 publications

(13 citation statements)

References 101 publications

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“…3D gridding tools can form a seamless step in an information flow of geological knowledge from 3D models into linked environmental models if they incorporate the capture of metadata and dependencies to support communication and feedback loops between disciplines ( Figure 11). Improving intersystem links and feedback loops in this way would encourage a more iterative transfer of information between geological and process models as proposed by DAgnese et al (1997) and others (Agada et al, 2014;Turner, 2006;Smith et al, 2012). v.…”

Section: Remaining Challengesmentioning

confidence: 99%

Improving geological and process model integration through TIN to 3D grid conversion

Watson

Richardson

Wood

et al. 2015

Computers & Geosciences

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The ability to extract properties from 3D geological framework models for use in the construction of conceptual and mathematical models is seen as increasingly important, however, tools and techniques are needed to support such information flows. Developing such methodologies will maximize the opportunity for information use and re-use, this is particularly important as the true value of such assets is not always known when they are first acquired. This paper briefly describes the cultural and technical challenges associated with the application of information derived from 3D geological framework models by hydrogeological process models. We examine how these issues are being addressed and present a tool, SurfGrid, which allows a user to generate 3D grids (voxels) of parameterized data from a series of geological surfaces. The procedures and tools described offer the ability to re-use expensively created assets by providing user friendly techniques that enable multidisciplinary scientists to extrapolate property distributions from geological models.

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Section: Remaining Challengesmentioning

confidence: 99%

Improving geological and process model integration through TIN to 3D grid conversion

Watson

Richardson

Wood

et al. 2015

Computers & Geosciences

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“…In this study, we use a high-resolution flow simulation model of the Amellago Island Outcrop, a middle Jurassic Carbonate ramp in the High Atlas Mountains of Morocco (Pierre et al, 2010;Amour et al, 2013;Agada et al, 2014a). The outcrop can be considered as an analogue for the highly productive carbonate reservoirs of the Arab D formation in Qatar (Al-Saad and Ibrahim, 2005;Al-Emadi et al, 2009).…”

Section: Matrix Characterisationmentioning

confidence: 99%

“…The average matrix permeability is 84mD while the average matrix porosity is 12%. Very heterogeneous lithologies are preserved in the simulation model including mollusc banks, mud mounds, patch reefs, sub-seismic faults and fractures (Agada et al, 2014a).…”

Section: Matrix Characterisationmentioning

confidence: 99%

“…Hydrocarbon recovery in carbonates, however, is typically low, due to multiscale heterogeneities and oil-to mixed-wet rock properties (Manrique et al, 2007;Montaron, 2008;Mohan et al, 2011). Low recovery factors are further influenced by complex connected high permeability fracture networks which establish preferential flow paths in the reservoir (e.g., Gale et al, 2004;Belayneh and Cosgrove, 2010;Agada et al, 2014a). Such variability in matrix architecture and fracture network connectivity is the main reason why fractured carbonate reservoirs show a large variety of flow behaviours, leading to significant uncertainties in their evaluation, performance prediction and management (e.g., Cosentino et al, 2001;Makel, 2007).…”

Section: Introductionmentioning

confidence: 99%

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Reduced Order Models for Rapid EOR Simulation in Fractured Carbonate Reservoirs

Agada¹,

Geiger²,

Elsheikh³

et al. 2015

SPE Reservoir Simulation Symposium

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Conventional simulation of fractured carbonate reservoirs is computationally expensive because multiscale heterogeneities and fracture-matrix transfer must be taken into account. The computational requirement increases exponentially when multiple simulation runs are required for sensitivity analysis and quantification of the uncertainty range. This can be prohibitive, especially for giant carbonate reservoirs. Yet, sensitivity analysis and uncertainty quantification are particularly important to analyse, determine and rank the impact of geological and engineering parameters on the economics and sustainability of different EOR techniques.We use experimental design to set up multiple screened simulations of a high-resolution model of a Jurassic Carbonate ramp, which is an analogue for the highly prolific reservoirs of the Arab D formation in Qatar. We consider CO 2 water-alternating-gas (WAG) injection, which has been shown to be a successful EOR method for carbonate reservoirs. The simulations are used as a basis for generating polynomial response surfaces for prediction of hydrocarbon recovery and net gas utilisation. We compare response surfaces from polynomial regression to response surfaces generated with polynomial chaos expansion (PCE). PCE allows for non-linear mapping of parameter uncertainty to the predicted results.In the current work, the geological parameter uncertainties affecting WAG modelling in fractured carbonates are evaluated. These include end-member fault transmissibility configurations, wettability scenarios, hysteresis models and fracture intensity. Effective fracture permeabilities are computed using discrete fracture networks (DFN) for sparsely distributed regional fractures. The results enable us to adequately explore the parameter space, quantify and rank the interrelated effect uncertain model parameters on CO2 WAG efficiency in fractured carbonate reservoirs. The results highlight the first order impact of fracture intensity, wettability and hysteresis on hydrocarbon recovery and net gas utilisation. Furthermore, reduced order (i.e. proxy) models enable us to calculate quick estimates of the probabilistic uncertainty range and achieve significant computational speed-up compared with the conventional Monte Carlo framework.

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“…On the other hand, reservoir fluid flow simulation models, generally span much coarser grids, typically tens to hundreds of metres, with high‐resolution models in the order of 10 m laterally and 0.1 m vertically (Agada et al . ). The obvious reason for coarse fluid flow models is computational limitations, as well as a means to manage the uncertainty through the averaging process, due to imperfect characterization at the fine scale.…”

Section: Introductionmentioning

confidence: 97%

Scale effects on modelling the seismic signature of gas: results from an outcrop analogue

Mangriotis

MacBeth

Briceno

2018

Geophysical Prospecting

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Numerous examples of reservoir fields from continental and marine environments involve thin‐bedded geology, yet, the inter‐relationship between thin‐bedded geology, fluid flow and seismic wave propagation is poorly understood. In this paper, we explore the 4D seismic signature due to saturation changes of gas within thin layers, and address the challenge of identifying the relevant scales and properties, which correctly define the geology, fluid flow and seismic wave propagation in the field. Based on the study of an outcrop analogue for a thin‐bedded turbidite, we model the time‐lapse seismic response to fluid saturation changes for different levels of model scale, and explore discrepancies in quantitative seismic attributes caused by upscaling. Our model reflects the geological complexity associated with thin‐bedded turbidites, and its coupling to fluid flow, which in turn affects the gas saturation distribution in space, and its time‐lapse seismic imprint. Rock matrix and fluid properties are modelled after selected fields to reproduce representative field models with realistic impedance contrasts. In addition, seismic modelling includes multiples, in order to assess their contribution in seismic propagation through thin gas layers. Our results show that multiples could contribute significantly to the measured amplitudes in the case of thin‐bedded geology. This suggests that forward/inverse modelling involving the flow simulation and seismic domains used in time‐lapse seismic interpretation should account for thin layers, when these are present in the geological setting.

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Numerical simulation of fluid-flow processes in a 3D high-resolution carbonate reservoir analogue

Cited by 30 publications

References 101 publications

Improving geological and process model integration through TIN to 3D grid conversion

Improving geological and process model integration through TIN to 3D grid conversion

Reduced Order Models for Rapid EOR Simulation in Fractured Carbonate Reservoirs

Scale effects on modelling the seismic signature of gas: results from an outcrop analogue

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