scholarly journals Comparison of Petrophysical Properties of Porous Rocks Using NMR, Micro-CT, and Fluid Flow Simulations

Geosciences ◽  
2021 ◽  
Vol 11 (12) ◽  
pp. 500
Author(s):  
Apoorv Jyoti ◽  
Ralf R. Haese
Keyword(s):  
Water Saturation ◽  
Image Resolution ◽  
Nuclear Magnetic Resonance Analysis ◽  
Ct Image ◽  
Petrophysical Properties ◽  
Micro Ct ◽  
Image Size ◽  
Flow Simulations ◽  
Transport Regime ◽  
Rock Types

Micro-computed tomography (micro-CT) is increasingly utilized to image the pore network and to derive petrophysical properties in combination with modelling software. The effect of micro-CT image resolution and size on the accuracy of the derived petrophysical properties is addressed in this study using a relatively homogenous sandstone and a heterogenous, highly porous bioclastic limestone. Standard laboratory procedures including NMR (nuclear magnetic resonance) analysis, micro-CT analysis at different image resolutions and sizes and pore-scale flow simulations were used to determine and compare petrophysical properties. NMR-derived pore-size distribution (PSD) was comparable to the micro-CT-derived PSD at a resolution of 7 µm for both the rock types. Porosity was higher using the water saturation method as compared to the NMR method in both rocks. The resolution did not show a significant effect on the porosity of the homogeneous sandstone, but porosity in the heterogeneous limestone varies depending on the location of the sub-sample. The transport regime in the sandstone was derived by simulations and changed with the resolution of the micro-CT image. The transport regime in the sandstone was advection-dominated at higher image resolution and diffusion-dominated when using a lower image resolution. In contrast, advection was the dominant transport regime for the limestone based on simulations using higher and lower image resolutions. Simulation-derived permeability for a 400 Voxel3 image at 7 µm resolution in the Berea sandstone matched laboratory results, although local heterogeneity within the rock plays an integral role in the permeability estimation within the sub-sampled images. The simulation-derived permeability was highly variable in the Mount Gambier limestone depending on the image size and resolution with the closest value to a laboratory result simulated with an image resolution of 2.5 µm and a size of 300 Voxel3. Overall, the study demonstrates the need to decide on micro-CT parameters depending on the type of petrophysical property of interest and the degree of heterogeneity within the rock types.

scholarly journals Petrophysical Properties of an Iraqi Carbonate Reservoir Using Well Log Evaluation

2020 ◽  
Vol 21 (1) ◽  
pp. 53-59
Author(s):  
Sarah S. Zughar ◽  
Ahmad A. Ramadhan ◽  
Ahmed K. Jaber
Keyword(s):  
Water Saturation ◽  
Carbonate Reservoir ◽  
Petrophysical Properties ◽  
Indicator Method ◽  
Rock Types ◽  
Fluid Saturation ◽  
Unit Thickness ◽  
Average Formation ◽  
Porous Zone ◽  
Mud Filtration

This research was aimed to determine the petrophysical properties (porosity, permeability and fluid saturation) of a reservoir. Petrophysical properties of the Shuiaba Formation at Y field are determined from the interpretation of open hole log data of six wells. Depending on these properties, it is possible to divide the Shuiaba Formation which has thickness of a proximately 180-195m, into three lithological units: A is upper unit (thickness about 8 to 15 m) involving of moderately dolomitized limestones; B is a middle unit (thickness about 52 to 56 m) which is composed of dolomitic limestone, and C is lower unit ( >110 m thick) which consists of shale-rich and dolomitic limestones. The results showed that the average formation water resistivity for the formation (Rw = 0.021), the average resistivity of the mud filtration (Rmf = 0.57), and the Archie parameters determined by the picket plot method, where m value equal to 1.94, n value equal to 2 and a value equal to 1. Porosity values and water saturation Sw were calculated along with the depth of the composition using IP V3.5 software. The interpretation of the computer process (CPI) showed that the better porous zone holds the highest amount of hydrocarbons in the second zone. From the flow zone indicator method, there are four rock types in the studied reservoir.

scholarly journals Water saturation modeling using modified J-function constrained by rock typing method in bioclastic limestone

2020 ◽  
Vol 75 ◽  
pp. 66
Author(s):  
Ya Deng ◽  
Rui Guo ◽  
Zhongyuan Tian ◽  
Limin Zhao ◽  
Dandan Hu ◽  
...  
Keyword(s):  
Water Saturation ◽  
Free Water ◽  
Petrophysical Properties ◽  
Saturation Model ◽  
Typing Method ◽  
Thin Sections ◽  
Rock Types ◽  
Rock Typing ◽  
Wireline Logs ◽  
Mercury Injection Capillary Pressure

Combining both geological and petrophysical properties, a reliable rock typing scheme can be achieved. Two steps are included in rock typing. Step 1: rocks are classified into lithofacies based on core observations and thin sections; Step 2: lithofacies are further subdivided into rock types according to petrophysical properties such as MICP (Mercury Injection Capillary Pressure) and K-Phi relationships. By correlating rock types to electrofacies (clusters of log data), we can group the target formation into 12 rock types. Then it is possible to predict the distributions of rock types laterally and vertically using wireline logs. To avoid the defect of the classical J-function saturation model that includes permeability which is quite uncertain especially in carbonate rocks, a modified J-function was created and used in the paper. In this function, water saturation is simply expressed as a function of height above free water level for a specific rock type. Different water saturation models are established for different rock types. Finally, the water saturation model has been successfully constructed and verified to be appropriate.

Micro-CT Image-based Analysis of Porous Urethane

2021 ◽  
Vol 2021.27 (0) ◽  
pp. 10E15
Author(s):  
Shintaro HOMMA ◽  
Naoki TAKANO ◽  
Syo TADA ◽  
Yuki NONOYAMA
Keyword(s):  
Ct Image ◽  
Micro Ct

Objective-Driven Solid-Surface-Roughness Characterization for Enhanced Nuclear-Magnetic-Resonance Petrophysics

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Shouxiang Mark Ma ◽  
Gabriela Singer ◽  
Songhua Chen ◽  
Mahmoud Eid
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Surface Roughness ◽  
Magnetic Resonance ◽  
Pore Size ◽  
Solid Surface ◽  
Micro Ct ◽  
Roughness Effects ◽  
Formation Evaluation ◽  
Petrophysical Parameters ◽  
Rock Types

Summary Typically, smooth solid surfaces of reservoir rocks are assumed in formation evaluation, such as nuclear-magnetic-resonance (NMR) petrophysics and reservoir-wettability characterization through contact-angle measurements. Measuring the degree of surface roughness (R), or smoothness, and evaluating its effects on formation evaluation are topics of much research. In this paper, we primarily focus on details in characterizing solid-surface roughness and its applications in NMR pore-sizeanalysis. R can be measured by contact techniques and noncontact techniques, such as stylus profilometer, atomic-force microscopy, and different kinds of optical measurements. Each technique has different sensitivities, measurement artifacts, resolutions, and field of view (FOV). Intuitively, although a finer resolution measurement provides the closest account of all surface details, the correspondingly small FOV might compromise the representativeness of the measurement, which is particularly challenging for charactering heterogeneous samples such as carbonates. To balance the FOV and measurement representativeness, and to minimize artifacts, laser scanner confocal microscopy (LSCM) is selected in this study. Results for the more than 27 rock samples tested indicate that rocks of similar rock types have similar R-values. Grainy limestones have relatively higher R-values compared with dolostones, consistent with the dolostone’s crystallization surface features. Muddy limestones have smoother surfaces, resulting in the lowest R-values among the rocks studied. For sandstones, R varies with clay types and content. For rocks containing two distinct minerals, two R-values are observed from the R profiles, which for these rock types justifies the use of two NMR surface relaxivity (ρ2) parameters for determining the pore-size distribution (PSD) from the NMR T2distribution. The novelty here is the integration of LSCM and NMR to obtain an NMR PSD relevant for permeability, capillary pressure, and other petrophysical parameters. Typically, ρ2 is calibrated using the total surface area from Brunauer-Emmett-Teller (BET; Brunauer et al. 1938) gas adsorption, but this underestimates the NMR pore size because of surface-roughness effects. In our novel approach, we use R measured from LSCM to correct ρ2 for surface-roughness effects, and thereby obtain the NMR pore size more relevant for permeability and other petrophysical parameters. We then compare the roughness-corrected NMR PSD against pore size from microcomputed tomography (micro-CT) scanning (which is roughness independent). The good agreement between roughness-corrected NMR and micro-CT pore sizes in the micropore region validates our new technique, and highlights the importance of surface-roughness characterization in NMR petrophysics.

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