Directional Permeability Dependence in Electroplated Permalloy Layers

2019 ◽  
Vol 3 (25) ◽  
pp. 123-135 ◽  
Author(s):  
Matthias Bedenbecker ◽  
Zbigniew Celinski ◽  
H. H. Gatzen
Keyword(s):  
Directional Permeability

Research of directional permeability inversion using flexural wave and its application

2016 ◽  
Author(s):  
Xu Xiaokai ◽  
Liufang Zhu ◽  
Jinyan Zhang ◽  
Liu Meijie ◽  
Zhai Yong
Keyword(s):  
Flexural Wave ◽  
Directional Permeability

An Approximate Method for Determining Areal Sweep Efficiency and Flow Capacity in Formations with Anisotropic Permeability

10.2118/16-pa ◽  
1961 ◽  
Vol 1 (04) ◽  
pp. 277-286 ◽  
Author(s):  
M. Mortada ◽  
G.W. Nabor
Keyword(s):  
Principal Axis ◽  
Bedding Plane ◽  
Sweep Efficiency ◽  
Simple Method ◽  
Anisotropic Permeability ◽  
Preferred Direction ◽  
Flow Capacity ◽  
Principal Axes ◽  
Special Cases ◽  
Directional Permeability

Abstract The effects of anisotropic or directional permeability on the areal sweep efficiency and the flow capacity are examined. The paper points out the importance of taking directional permeability into consideration in planning a flood. It analyzes the two-dimensional flow pattern associated with the skewed line drive for a unit mobility ratio. The direct and staggered line drives are treated as special cases of the skewed line drive. Analytical expressions are developed for the areal sweep efficiency at breakthrough and the flow capacity. They are related to the spacing between like wells, the distance between a row of injectors and the nearest row of producers, and the degree of skewness of the line drive. The latter quantity is defined such that it is equal to zero for the direct line drive and equals one-half for the staggered line drive. The a real sweep efficiency and the flow capacity depend also on the orientation of the flood pattern with respect to the principal axis of anisotropy. The paper provides a simple method for determining the a real sweep efficiency and the flow capacity for a formation in which the permeability in the bedding plane is anisotropic. Introduction Directional or anisotropic permeability is manifested by the ability of the formation to conduct fluids more readily along certain preferred directions. This situation occurs in many producing formations and is usually attributed to depositional features in which the sand grains are oriented in a preferred direction. In some cases it results from the formation of a major and a minor fracture system. Directional permeability should be taken into account in many phases of the production and exploration activities. Recognizing its existence in the formation of interest and planning accordingly can lead to increased recovery and substantial savings. For instance, the areal sweep efficiency in a water flood depends to a great extent on the orientation of the flood pattern with respect to the principal axis of permeability. Anisotropic permeability is specified by the directions of its three principal axes and the permeability along each axis. The principal axes of permeability are mutually perpendicular. This paper deals with the areal sweep efficiency at breakthrough and the flow capacity for formations with anisotropic permeability. The flood pattern considered consists of alternate rows of injecting and producing wells. The rows of wells are parallel and form a developed, skewed line drive which is illustrated in Fig. 1. The staggered and direct line drives are treated as special cases of the skewed line drive.

Directional-Permeability Assessment in Formations With Complex Pore Geometry With a New Nuclear-Magnetic-Resonance-Based Permeability Model

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1436-1449 ◽  
Author(s):  
Lu Chi ◽  
Zoya Heidari
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Pore Geometry ◽  
Pore Scale ◽  
Rock Permeability ◽  
Permeability Model ◽  
Pore Connectivity ◽  
Anisotropic Permeability ◽  
Rock Samples ◽  
Directional Permeability

Summary This paper proposes a new method for directional-permeability assessment with nuclear-magnetic-resonance (NMR) measurements. Conventional techniques for permeability assessment from NMR measurements include empirical correlations such as SDR (Schlumberger-Doll-Research) and Coates models. However, carbonate rocks are known for lack of good correlations between pore-body-size and pore-throat-size, which makes it challenging and often unreliable to estimate permeability from NMR T2 (spin-spin relaxation time) distribution in carbonate formations with complex pore structure. It also was proposed that conventional permeability models can be improved by incorporating an estimated pore-connectivity factor. However, none of the previously introduced techniques reflects the anisotropic characteristics of rock permeability. The new NMR-based directional-permeability model, introduced in this paper, incorporates a directional pore-connectivity factor into a conventional NMR-based permeability model. We introduce two approaches to quantify the directional pore-network connectivity of rock samples with pore-scale images. The first approach calculates directional pore connectivity in 3D pore-scale images with a topological technique. The second approach combines image analysis and electrical formation factor. The new NMR-based permeability model enables assessment of rock permeability in any desired direction. We successfully calibrated and tested the introduced NMR-based permeability model on carbonate, sandstone, and sandpack samples with complex pore geometry or anisotropic permeability. The anisotropic permeability used for calibration and test purposes was obtained by the lattice Boltzmann method (LBM) simulations on microcomputed tomography (CT) images of rock samples. The comparison between the permeability estimates with our new NMR model and conventional NMR models (e.g., SDR and Coates models) demonstrated that the NMR-based directional-permeability model significantly improves assessment of rock permeability, by reflecting rock's anisotropic characteristics and minimizing calibration efforts. The outcomes of this research can significantly improve permeability assessment in complex carbonate reservoirs and anisotropic sandstone reservoirs, and can be extended further to organic-rich mudrock formations.

Whole Core Analysis - Experience and Challenges

2005 ◽  
Vol 8 (06) ◽  
pp. 460-469 ◽  
Author(s):  
Mehdi M. Honarpour ◽  
Nizar F. Djabbarah ◽  
Krishnaswamy Sampath
Keyword(s):  
Electrical Properties ◽  
Capillary Pressure ◽  
Carbonate Rocks ◽  
Water Saturation ◽  
Core Analysis ◽  
Confining Stress ◽  
X Ray ◽  
X Ray Imaging ◽  
Directional Permeability ◽  
Special Core Analysis

Summary Whole-core analysis is critical for characterizing directional permeability in heterogeneous, fractured, and/or anisotropic rocks. Whole-core measurements are essential for heterogeneous reservoirs because small-scale heterogeneity may not be appropriately represented in plug measurements. For characterization of multiphase-flow properties (special core analysis) in heterogeneous rocks, whole-core analysis is also required. Few commercial laboratories are equipped to conduct routine measurements on whole cores up to 4 in. in diameter and up to 8 in. long and, importantly, under simulated reservoir net confining stress (NCS). Special whole-core analyses are rarely conducted because of the difficulties associated with establishing a representative water saturation in drainage capillary pressure experiments and measuring directional effective permeabilities. Electrical properties also can be measured on whole cores to determine porosity and saturation exponents for situations in which resistivity tools are used in horizontal or highly deviated wells. In this paper, we provide an overview of routine and special core-analysis measurements on whole cores. Results from selected heterogeneous sandstone and carbonate rocks will be discussed. We also will show how the results relate to data obtained from plug analysis, with particular emphasis on directional absolute permeability, trapped-gas and fluid saturations, and the effect of NCS. Finally, we will describe a novel apparatus for special core analysis on whole cores and provide examples of the capabilities of the system. In this paper, we will present:• Recommended techniques for the determination of directional absolute and effective permeability and for establishing initial water saturation in whole cores.• Improved understanding of the effect of scale (sample size) on the measured properties.• Description of a novel whole-core apparatus with measurement of fluid-saturation distribution using in-situ saturation monitoring. Introduction Reservoir rocks are heterogeneous, especially carbonate rocks, in which more than 50% of the world's hydrocarbon reserves are deposited. Fig. 1 shows an example of variability in rock characteristics as observed in a carbonate-rockout crop in Oman. The heterogeneous nature of these rocks tends to become more apparent as attempts are made to measure their petrophyscal properties at various scales. An example of permeability variation in a plug from a carbonate formation is shown in Fig. 2. Single-phase air permeability varies by three orders of magnitude over the distance of a few centimeters in this core plug. This dual-porosity behavior impacts the spontaneous-imbibition performance significantly (Fig. 3). Technology at Commercial Laboratories Selected commercial laboratories have capabilities to appropriately clean and prepare whole cores, perform core X-ray imaging, and measure basic properties such as directional permeability and porosity under a maximum confining stress of 5,000 psi. Available technologies for imaging, sample preparation, and routine core analysis are summarized in the following sections. Special-core-analysis capabilities at commercial laboratories are rare. Only one or two laboratories are capable of measuring primary-drainage gas/water capillary pressure and gas/water or oil/water electrical properties on whole cores at confining stress. Whole-Core Imaging and Screening Whole-core photography and X-ray imaging provide information about surface features and internal structure. The computed tomography (CT) scan provides evidence of fractures, vugs, and heterogeneities as indicated by the extent in the variation of CT density. X-ray fluoroscopy and CT are two of the most practical X-ray scanning techniques used to characterize core-level heterogenieties and to explain their effect on horizontal and vertical permeabilities. CT-scanning algorithms should often be modified to obtain images free of artifacts and with better than0.5-mm horizontal and 1-mm vertical resolutions.

scholarly journals PERSONAL COMPUTER-BASED DIGITAL PETROPHYSICS

2017 ◽  
Vol 35 (2) ◽  
Author(s):  
Ricardo Leiderman ◽  
Andre M. B. Pereira ◽  
Francisco M. J. Benavides ◽  
Carla S. Silveira ◽  
Rodrigo M. R. Almeida ◽  
...  
Keyword(s):  
Computed Tomography ◽  
Rock Physics ◽  
Young Modulus ◽  
X Ray ◽  
Micro Scale ◽  
Representative Volume ◽  
Computational Implementation ◽  
Computer Based ◽  
X Ray Computed ◽  
Directional Permeability

ABSTRACT. In the present work, we describe our experience with digital petrophysics, enhancing our choices for performing the related tasks. The focus is on the use of ordinary personal computers. To our best knowledge, some of the information and hints we give cannot be found in the literature and we hope they may be useful to researchers that intend to work on the development of this new emerging technology. We have used micro-scale X-ray computed tomography to image the rock samples and, in that sense, we address here the issue of the corresponding image acquisition and reconstruction parameters adjustment. In addition, we discuss the imaging resolution selection and illustrate the issue of the representative volume choice with the aid of two examples. The examples corroborate the notion that it is much more challenging to define a representative volume for carbonate samples than for sandstone samples. We also discuss the image segmentation and describe in details the Finite Element computational implementation we developed to perform the numerical simulations for estimating the effective Young modulus from segmented microstructural images. We indicate the respective computational costs and show that our implementation is able to handle comfortably images of 300×300×300 voxels. We use a commercially available Finite Volume software to estimate the effective absolute directional permeability. Keywords: rock physics, micro-scale X-ray computed tomography, multi-scale homogenization, effective elastic moduli, representative volume. RESUMO. No presente trabalho descrevemos nossa experiência com Petrofísica Digital, dando ênfase às nossas escolhas para a realização das tarefas relacionadas. O foco é no uso de computadores pessoais e, salvo melhor juízo, algumas das informações e dados que apresentamos não podem ser achados na literatura. Nós adquirimos as imagens digitais de amostras de rochas com o auxílio de microtomografia computadorizada por raio-X e, nesse sentido, discutimos aqui o ajuste dos parâmetros de aquisição e reconstrução de imagens. Além disso, nós discutimos a questão da seleção do volume representativo e sua relação com o tamanho e resolução da imagem digital, mostrando dois exemplos ilustrativos. Os exemplos corroboram a noção de que é muito mais difícil definir um volume representativo tratável para carbonatos do que para arenitos. Nós também discutimos a segmentação de imagens no contexto da Petrofísica Digital e descrevemos em detalhes o código de Elementos Finitos por nós desenvolvido para estimar o módulo de Young efetivo de amostras de rochas a partir de suas imagens microtomográficas, indicando o respectivo custo computacional. Nós mostramos que nossas escolhas levaram a uma implementação computacional capaz de lidar confortavelmente com imagens de até 300×300×300 voxels. Por fim, descrevemos o uso do pacote comercial de Volumes Finitos para estimar a permeabilidade absoluta efetiva das amostras de rocha. Palavras-chave: física de rochas, microtomografia computadorizada por raio-X, homogeneização multiescala, módulo de Young efetivo, volume representativo.

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