Numerical Relative Permeability Upscaling Based on Digital Rock Analysis

2019 ◽  
Author(s):  
Qian Sun ◽  
Na Zhang ◽  
Nayef Alyafei ◽  
Yuhe Wang ◽  
Mohamed Fadlelmula
Keyword(s):  
Relative Permeability ◽  
Digital Rock ◽  
Permeability Upscaling ◽  
Rock Analysis

Need a Faster Measure of Relative Permeability? Take a CT Scan and Follow With Digital Rock Analysis

2017 ◽  
Vol 69 (08) ◽  
pp. 28-31 ◽  
Author(s):  
Stephen Rassenfoss
Keyword(s):  
Ct Scan ◽  
Relative Permeability ◽  
Digital Rock ◽  
Rock Analysis

Formation Characterization and Production Forecast of Tight Sandstone Formations in Daqing Oilfield Through Digital Rock Technology

2021 ◽  
Author(s):  
Danhua Leslie Zhang ◽  
Xiaodong Shi ◽  
Chunyan Qi ◽  
Jianfei Zhan ◽  
Xue Han ◽  
...  
Keyword(s):  
High Resolution ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Surfactant Solution ◽  
Fluid Models ◽  
Pore Scale ◽  
Field Development ◽  
Digital Rock ◽  
Small Pore ◽  
Sem Imaging

Abstract With the decline of conventional resources, the tight oil reserves in the Daqing oilfield are becoming increasingly important, but measuring relative permeability and determining production forecasts through laboratory core flow tests for tight formations are both difficult and time consuming. Results of laboratory testing are questionable due to the very small pore volume and low permeability of the reservoir rock, and there are challenges in controlling critical parameters during the special core analysis (SCAL) tests. In this paper, the protocol and workflow of a digital rock study for tight sandstones of the Daqing oilfield are discussed. The workflow includes 1) using a combination of various imaging methods to build rock models that are representative of reservoir rocks, 2) constructing digital fluid models of reservoir fluids and injectants, 3) applying laboratory measured wettability index data to define rock-fluid interaction in digital rock models, 4) performing pore-scale modelling to accelerate reservoir characterization and reduce the uncertainty, and 5) performing digital enhanced oil recovery (EOR) tests to analyze potential benefits of different scenarios. The target formations are tight (0.01 to 5 md range) sandstones that have a combination of large grain sizes juxtaposed against small pore openings which makes it challenging to select an appropriate set of imaging tools. To overcome the wide range of pore and grain scales, the imaging tools selected for the study included high resolution microCT imaging on core plugs and mini-plugs sampled from original plugs, overview scanning electron microscopy (SEM) imaging, mineralogical mapping, and high-resolution SEM imaging on the mini-plugs. High resolution digital rock models were constructed and subsequently upscaled to the plug level to differentiate bedding and other features could be differentiated. Permeability and porosity of digital rock models were benchmarked against laboratory measurements to confirm representativeness. The laboratory measured Amott-Harvey wettability index of restored core plugs was honored and applied to the digital rock models. Digital fluid models were built using the fluid PVT data. A Direct HydroDynamic (DHD) pore-scale flow simulator based on density functional hydrodynamics was used to model multiphase flow in the digital experiments. Capillary pressure, water-oil, surfactant solution-oil, and CO2-oil relative permeability were computed, as well as primary depletion followed with three-cycle CO2 huff-n-puff, and primary depletion followed with three-cycle surfactant solution huff-n-puff processes. Recovery factors were obtained for each method and resulting values were compared to establish most effective field development scenarios. The workflow developed in this paper provides fast and reliable means of obtaining critical data for field development design. Capillary pressure and relative permeability data obtained through digital experiments provide key input parameters for reservoir simulation; production scenario forecasts help evaluate various EOR methods. Digital simulations allow the different scenarios to be run on identical rock samples numerous times, which is not possible in the laboratory.

Capillary Pressure and Relative Permeability Assessment on Whole core samples from a giant middle easteren carbonate reservoir utilizing digital rock physics

2014 ◽  
Author(s):  
Safouh Koronfol ◽  
Abraham Grader ◽  
Michael Suhrer ◽  
Jonas Toelke ◽  
Yaoming Mu ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Rock Physics ◽  
Carbonate Reservoir ◽  
Digital Rock Physics ◽  
Digital Rock ◽  
Core Samples

Correlating Recovery Efficiency to Pore Throat Characteristics using Digital Rock Analysis

2015 ◽  
Author(s):  
Dandan Hu ◽  
Douglas Wyatt ◽  
Cheng Chen ◽  
Vladimir Martysevich
Keyword(s):  
Recovery Efficiency ◽  
Pore Throat ◽  
Digital Rock ◽  
Rock Analysis

Digital Rock Analysis: A Case Study on Characterization of Capillary Transition Zones in Carbonate Reservoirs

2018 ◽  
Author(s):  
H. Sun ◽  
H. Belhaj ◽  
A. Bera ◽  
L. Liu ◽  
G. Tao ◽  
...  
Keyword(s):  
Carbonate Reservoirs ◽  
Transition Zones ◽  
Digital Rock ◽  
Rock Analysis

Application of Digital Rock Analysis for Evaluation of Gas-Condensate Transport

2021 ◽  
Author(s):  
Oleg Dinariev ◽  
Nikolay Evseev
Keyword(s):  
Density Functional ◽  
Development Planning ◽  
Gas Condensate ◽  
Computational Method ◽  
Kinetic Properties ◽  
Pore Scale ◽  
Digital Rock ◽  
Compositional Model ◽  
Rock Analysis ◽  
Phase Mobility

Abstract The computational method for gas-condensate phase permeabilities is presented using digital rock analysis. The proposed method combines: a) construction of high-resolution tomographic images of the pore space; b) development of compositional model of a gas-condensate mixture at pore-scale including rheology, fluid-fluid and fluid-rock interfacial tension coefficients, and thermodynamic and kinetic properties of fluid phases; c) 3D pore-scale modeling of multiphase transport and interfacial chemical component exchange using the density functional hydrodynamics numerical simulator. This digital rock analysis workflow is applied to the gas-condensate transport at pore-scale. The numerical simulations are carried out using the 3D digital rock model constructed by X-ray microCT imaging of the rock pore structure. By specifying different gas and condensate fractions and injection rates it has been possible to obtain computationally 3D saturation distribution fields and the phase permeabilities. The results of 3D density functional hydrodynamic simulations provide the comprehensive description of gas-condensate mixture at pore-scale including hydrodynamic desaturation effects and phase transition kinetic phenomena. It is demonstrated that condensate distribution in pores, phase mobility thresholds and phase permeabilities are dependent on wettability properties and flow rates. It is shown that condensate composition in individual pores is also dynamically dependent on flow regimes. These results can be used in field development planning for the improved evaluation of condensate banking in the vicinity of production wells and condensate losses in the reservoir.

Digital Rock Analysis - Providing SCAL Properties for the Matrix of Tight Carbonates of the Najmah-Sargelu Formation, Kuwait

2016 ◽  
Author(s):  
P. Mukherjee ◽  
D. SinghaRay ◽  
A. Golab ◽  
J. Al-Kandari ◽  
R. B. Quttainah ◽  
...  
Keyword(s):  
Digital Rock ◽  
The Matrix ◽  
Rock Analysis
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