Estimation of pseudo relative permeability curves for a heterogeneous reservoir with a new automatic history matching algorithm

Fayazi, Amir; Bagherzadeh, Hadi; Shahrabadi, Abbas

doi:10.1016/j.petrol.2016.01.013

Cited by 22 publications

(8 citation statements)

References 36 publications

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“…It should be noted that the number of function evaluations required for the BADS algorithm to achieve relatively stable convergence is noticeably small compared with previous algorithms relative to the specific problem of relative permeability estimation. For example, Zhang et al [51], Zhou et al [25], and Fayazi et al [59] demonstrated that the EnKF, LM, and genetic algorithm (GA) require respectively ≈1000, ≈950, and ≈500 simulation runs to achieve stable convergence. This highlights the efficiency of the BADS algorithm in assisted history matching.…”

Section: Convergence Trend Of the Bads Algorithmmentioning

confidence: 99%

Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Zhang

et al. 2021

Energies

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The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.

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Section: Convergence Trend Of the Bads Algorithmmentioning

confidence: 99%

Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Zhang

et al. 2021

Energies

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“…This proves that flow-based upscaling techniques can be adequate to represent static behavior, but upscaling dynamic data through pseudo-relative permeability curves is essential when using conventional coarse grids. Several works (Hearn, 1971;Al-Otaibi and Al-Majed, 1998;Fayazi et al, 2016;Fahad et al, 2017) present methods to use pseudo-relative permeability curves for upscaling-matching purposes or converting dual-medium flow models into single medium. However, the study of pseudo-relative permeability curves is beyond the scope of this work.…”

Section: Figure 14mentioning

confidence: 99%

Flow Simulation Using Local Grid Refinements to Model Laminated Reservoirs

Correia

Maschio

Schiozer

2018

Oil & Gas Science and Technology - Rev. IFP Energies nouvel

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Super-giant carbonate fields, such as Ghawar, in Saudi Arabia, and Lula, at the Brazilian pre-salt, show highly heterogeneous behavior that is linked to high permeability intervals in thin layers. This article applies Local Grid Refinements (LGR) integrated with upscaling procedures to improve the representation of highly laminated reservoirs in flow simulation by preserving the static properties and dynamic trends from geological model. This work was developed in five main steps: (1) define a conventional coarse grid, (2) define LGR in the conventional coarse grid according to super-k and well locations, (3) apply an upscaling procedure for all scenarios, (4) define LGR directly in the simulation model, without integrate geological trends in LGR and (5) compare the dynamic response for all cases. To check results and compare upscaling matches, was used the benchmark model UNISIM-II-R, a refined model based on a combination of Brazilian Pre-salt and Ghawar field information. The main results show that the upscaling of geological models for coarse grid with LGR in highly permeable thin layers provides a close dynamic representation of geological characterization compared to conventional coarse grid and LGR only near-wells. Pseudo-relative permeability curves should be considered for (a) conventional coarse grid or (b) LGR scenarios under dual-medium flow simulations as the upscaling of discrete fracture networks and dual-medium flow models presents several limitations. The conventional approach of LGR directly in simulation model, presents worse results than LGR integrated with upscaling procedures as the extrapolation of dynamic properties to the coarse block mismatch the dynamic behavior from geological characterization. This work suggests further improvements for results for upscaling procedures that mask the flow behavior in highly laminated reservoirs.

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“…However, whether using a cutoff procedure for permeability or upscaling facies model, both have their limitations as it is a controversial decision to assume that a coarser block that intercepts both super-k features and background facies has a single representative relative-permeability curve that represents both flow units (Al-Otaibi and Al-Majed, 1998). Several works Al-Otaibi and Al-Majed, 1998;Fayazi et al, 2016;Saalfeld and Schiozer, 2016;Hearn, 1971) study pseudo-relative permeability curves for upscaling matching purposes or converting dual-medium flow models into single. However, as pseudo-relative permeability curves are beyond the scope of this work we consider a cutoff procedure based on a histogram match between the facies properties and the rock-type properties from the coarser scale.…”

Section: (A) Implicit Representation Of Super-k (Imp)mentioning

confidence: 99%

Integration of Highly Permeable Thin Layers Into Flow Simulation

Correia

Schiozer

2017

SPE Europec Featured at 79th EAGE Conference and Exhibition

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Giant reservoirs such as Lula (Santos Oil Basin, Brazil) and Ghawar (Saudi Arabia) have high permeability intervals, known as super-k zones, associated with thin layers. Modeling these small-scale flow features in large-scale simulation models is complex. Current methods are limited by high computational costs or simplifications that mismatch the representation of these features in simulation grid blocks. This work has two purposes: (1) present an upscaling workflow to integrate highly laminated or inter-bedded reservoirs with thin, highly permeable layers in reservoir simulations through a combination of (a) an explicit modeling of super-k layers using Parsons (1966) formula and (b) dualmedium flow models, and (2) compare this method with two conventional upscaling approaches, available in commercial software. We use the benchmark model UNISIM-II-R, a fine single-porosity grid based on field information from the Brazilian Pre-salt and Ghawar oil fields, as the reference solution to compare the upscaling matching between the three methods. We compare; oil recovery, water cut, average reservoir pressure, waterfront, and the time consumption for simulation. Our proposed parsons dual-medium (PDP) methodology achieved better upscaling matches with the reference model and had minimal time consumption when compared with the representation of super-k layers through an implicit matrix modelling by single porosity flow models (IMP) and through the explicit representation of super-k zones in the fracture system of dual-medium flow models (DFNDP).

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Estimation of pseudo relative permeability curves for a heterogeneous reservoir with a new automatic history matching algorithm

Cited by 22 publications

References 36 publications

Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Flow Simulation Using Local Grid Refinements to Model Laminated Reservoirs

Integration of Highly Permeable Thin Layers Into Flow Simulation

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