Predicting the Performance of the Acid-Stimulation Treatments in Carbonate Reservoirs With Nondestructive Tracer Tests

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1238-1253 ◽  
Author(s):  
A.S.. S. Zakaria ◽  
H.A.. A. Nasr-El-Din ◽  
M.. Ziauddin
Keyword(s):  
Porous Media ◽  
Pore Structure ◽  
Carbonate Rocks ◽  
Tracer Tests ◽  
Structure Characterization ◽  
Hydrochloric Acid Concentration ◽  
Thin Sections ◽  
Characterization Methods ◽  
Core Samples ◽  
Flow Through

Summary Carbonate formations are very complex in their pore structure and exhibit a wide variety of pore classes, such as interparticle porosity, moldic porosity, vuggy porosity, and microporosity. Geologists have defined carbonate pore classes on the basis of sedimentology, thin sections, and porosity/permeability relationships, but the question remains concerning how these pore classes govern the acid flow through porous media. Core samples from six different carbonates, mainly limestone, were selected for the study. The samples were first investigated with thin-section analysis, high-pressure mercury-injection tests, and nuclear-magnetic-resonance measurements for pore-structure characterization, and X-ray diffraction for mineralogy examination. Next, tracer experiments were conducted, and the tracer-concentration profiles were analyzed to quantify the carbonate pore-scale heterogeneity. The heterogeneity is expressed with a parameter f—the available fraction of pore structure contributing to the flow. The data were used to study the flow of acid through carbonate rocks and correlate the pore classes to the acid response. More than 30 acid-coreflood experiments were conducted at 150°F and a hydrochloric acid concentration of 15 wt% on 1.5 × 6-in. core samples at different injection rates on each carbonate rock type. The objective of these sets of experiments is to determine the acid pore volume to breakthrough for each carbonate pore class. The findings of this study help us to connect the results from different characterization methods to the acid flow through the porous media of carbonate rocks. It was also found that the response of the acid depends on the carbonate pore classes. Application to the design of matrix acid treatments in carbonate rocks is discussed.

Fabrication of a Microchannel Device With a Three-Dimensional Pore Network Using a Sacrificial Sugar Template

2020 ◽  
Author(s):  
Haipeng Zhang ◽  
Tomer Palmon ◽  
Seunghee Kim ◽  
Sangjin Ryu
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Pore Structure ◽  
Three Dimensional ◽  
Pore Network ◽  
Compressed Air ◽  
Microfluidic Channels ◽  
Two Phase ◽  
Flow Through ◽  
Phase Fluid

Abstract Porous media compressed air energy storage (PM-CAES) is an emerging technology that stores compressed air in an underground aquifer during the off-peak periods, to mitigate the mismatch between energy supplies and demands. Thus, PM-CAES involves repeated two-phase fluid flow in porous media, and ensuring the success of PM-CAES requires a better understanding of repetitive two-phase fluid flow through porous media. For this purpose, we previously developed microfluidic channels that retain a two-dimensional (2D) pore network. Because it was found that the geometry of the pore structure significantly affects the patterns and occupational efficiencies of a non-wetting fluid during the drainage-imbibition cycles, a more realistic microfluidic model is needed to reflect the three-dimensional (3D) nature of pore structures in the underground geologic formation. In this study, we developed an easy-to-adopt method to fabricate a microfluidic device with a 3D random pore network using a sacrificial sugar template. Instead of using a master mold made in photolithography, a sacrificial mold was made using sugar grains so that the mold could be washed away after PDMS curing. First, we made sugar templates with different levels of compaction load, and found that the thickness of the templates decreased as the compaction load increased, which suggests more packing of sugar grains and thus lower porosity in the template. Second, we fabricated PDMS porous media using the sugar template as a mold, and imaged their pore structure using micro computed tomography (micro-CT). Pores within PDSM samples appeared more tightly packed as the compacting force increased. Last, we fabricated a prototype PDMS channel device with a 3D pore network using a sugar template, and visualized flow through the pore network using colored water. The flow visualization result shows that the water was guided by the random pores and that the resultant flow pattern was three dimensional.

scholarly journals Determination of NMR T2 Cutoff and CT Scanning for Pore Structure Evaluation in Mixed Siliciclastic–Carbonate Rocks before and after Acidification

Energies ◽  
2020 ◽  
Vol 13 (6) ◽  
pp. 1338 ◽  
Author(s):  
Mengqi Wang ◽  
Jun Xie ◽  
Fajun Guo ◽  
Yawei Zhou ◽  
Xudong Yang ◽  
...  
Keyword(s):  
Pore Structure ◽  
Carbonate Rocks ◽  
Carbonate Rock ◽  
Experimental Results ◽  
Normal Distribution Function ◽  
Core Samples ◽  
Irreducible Water Saturation ◽  
Significant Difference ◽  
Before And After ◽  
Structure Evaluation

Nuclear magnetic resonance (NMR) is used widely to characterize petrophysical properties of siliciclastic and carbonate rocks but rarely to study those of mixed siliciclastic–carbonate rocks. In this study, 13 different core samples and eight acidified core samples selected amongst those 13 from the Paleogene Shahejie Formation in Southern Laizhouwan Sag, Bohai Bay Basin, were tested by scanning electron microscopy (SEM), micro-nano-computed tomography (CT), and NMR. SEM and CT results revealed a complex pore structure diversity, pore distribution, and pore-throat connectivity in mixed reservoirs. Sixteen groups of NMR experiments addressed changes in these properties and permeabilities of mixed siliciclastic–carbonate rocks before and after acidification to determine its effects on such reservoirs. NMR experimental results showed no “diffusion coupling” effect in mixed siliciclastic–carbonate rocks. Distributions of NMR T2 cutoff values (T2C) are closely related to the pore structure and lithologic characteristics before and after acidification. The T2C index separates irreducible and movable fluids in porous rocks and is a key factor in permeability prediction. Centrifugation experiments showed that, before acidification, the T2C of mixed siliciclastic–carbonate rocks with 60–90% siliciclastic content (MSR) ranged widely from 1.5 to 9.8 ms; the T2C of mixed siliciclastic–carbonate rocks with 60–90% carbonate content (MCR) ranged from 1.8 to 5.6 ms. After acidification, the T2C of MSR ranged widely from 2.6 to 11.6 ms, the T2C of MCR ranged from 1.5 to 5.6 ms, and no significant difference was observed between MCR reservoirs. Based on an analysis of the morphology of NMR T2 spectra, we propose a new T2 cutoff value prediction method for mixed siliciclastic–carbonate rocks based on a normal distribution function to predict various T2C values from morphological differences in NMR T2 spectra and to calculate the irreducible water saturation (Swir), i.e., the ratio of irreducible total fluid volume to effective porosity. The reliability of the proposed method is verified by comparing predicted T2C and Swir values with those from NMR experimental results. New experiments and modeling demonstrate the applicability of NMR for the petrophysical characterization of mixed siliciclastic–carbonate rock reservoirs. Our results have potential applications for identification and evaluation of mixed siliciclastic–carbonate rock reservoirs using NMR logging.

Numerical Simulation for Heat and Fluid Flow Through Porous Media

2011 ◽  
Author(s):  
Masayuki Kaneda ◽  
Yusuke Matsushima ◽  
Kazuhiko Suga
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Pore Structure ◽  
Porous Wall ◽  
Constant Heat Flux ◽  
Face Centered Cubic ◽  
Flow Through ◽  
Face Centered ◽  
Boltzmann Method ◽  
Heat And Fluid Flow

Heat and Fluid flow through infinite porous media is numerically studied. The pore structure considered is body-centered cubic (BCC) and face-centered cubic (FCC) whose porosity is ranged 0.93–0.98 by changing the pore diameter. For the thermal condition, a constant heat flux from the porous wall is considered. The heat and fluid flow simulations are carried out separately by the lattice Boltzmann method (LBM). It is confirmed that the LBM can simulate them properly and the permeability depends on the pore structure compared at the same porosity. The heat transfer coefficient is found to be affected not only by the permeability but also the pore structure. That is, even at the same permeability, the Nusselt number depends on the structure.

scholarly journals Pore Structure and Limit Pressure of Gas Slippage Effect in Tight Sandstone

2013 ◽  
Vol 2013 ◽  
pp. 1-7 ◽  
Author(s):  
Lijun You ◽  
Kunlin Xue ◽  
Yili Kang ◽  
Yi Liao ◽  
Lie Kong
Keyword(s):  
Porous Media ◽  
Pore Structure ◽  
Gas Flow ◽  
Gas Permeability ◽  
Flow In Porous Media ◽  
Slip Effect ◽  
Tight Sandstone ◽  
The Core ◽  
Core Samples ◽  
Limit Pressure

Gas slip effect is an important mechanism that the gas flow is different from liquid flow in porous media. It is generally considered that the lower the permeability in porous media is, the more severe slip effect of gas flow will be. We design and then carry out experiments with the increase of backpressure at the outlet of the core samples based on the definition of gas slip effect and in view of different levels of permeability of tight sandstone reservoir. This study inspects a limit pressure of the gas slip effect in tight sandstones and analyzes the characteristic parameter of capillary pressure curves. The experimental results indicate that gas slip effect can be eliminated when the backpressure reaches a limit pressure. When the backpressure exceeds the limit pressure, the measured gas permeability is a relatively stable value whose range is less than 3% for a given core sample. It is also found that the limit pressure increases with the decreasing in permeability and has close relation with pore structure of the core samples. The results have an important influence on correlation study on gas flow in porous medium, and are beneficial to reduce the workload of laboratory experiment.

Pore-scale modeling of elastic wave propagation in carbonate rocks

Geophysics ◽  
2015 ◽  
Vol 80 (1) ◽  
pp. D51-D63 ◽  
Author(s):  
Zizhen Wang ◽  
Ruihe Wang ◽  
Ralf J. Weger ◽  
Tianyang Li ◽  
Feifei Wang
Keyword(s):  
Porous Media ◽  
Wave Propagation ◽  
Elastic Wave ◽  
Pore Structure ◽  
Wave Velocity ◽  
Carbonate Rocks ◽  
P Wave ◽  
Pore Scale ◽  
Scale Modeling ◽  
P Wave Velocity

The relationship between P-wave velocity and porosity in carbonate rocks shows a high degree of variability due to the complexity of the pore structure. This variability introduces high uncertainties to seismic inversion, amplitude variation with offset analysis, porosity estimation, and pore-pressure prediction based on velocity data. Elastic wave propagation in porous media is numerically modeled on the pore scale to investigate the effects of pore structure on P-wave velocities in carbonate rocks. We built 2D models of porous media using pore structure information and the similarity principle. Then, we simulated normal incidence wave propagation using finite element analysis. Finally, the velocity was determined from received modeled signals by means of crosscorrelation. The repeatability and accuracy of this modeling process was verified carefully. Based on the modeling results, a simple formulation of Sun’s frame flexibility factor ([Formula: see text]), aspect ratio (AR, the ratio of the major axis to the minor axis), and pore density was developed. The numerical simulation results indicated that the P-wave velocity increases as a power function as the AR increases. Pores with small AR ([Formula: see text]) or large [Formula: see text] created softening effects that decrease P-wave velocity significantly. The P-wave velocity of carbonate rocks was dispersive; it depends on the ratio of the wavelength to pore size ([Formula: see text]). Such scale-dependent dispersion was more evident for carbonate rocks with higher porosity, lower AR, and/or lower P-wave impedance of pore fluids. The P-wave velocity of carbonate rocks with complicated pore geometries (low AR, high [Formula: see text], small [Formula: see text]) was much lower than that of rocks with simple pore geometries (high AR, small [Formula: see text], large [Formula: see text]) at low and high [Formula: see text]. The pore-scale modeling of elastic wave properties of porous rocks may explain the poor velocity-porosity correlation in carbonate rocks.

scholarly journals Review on Pore Structure Characterization and Microscopic Flow Mechanism of CO 2 Flooding in Porous Media

2020 ◽  
Vol 9 (1) ◽  
pp. 2000787
Author(s):  
Yong Tang ◽  
Chengxi Hou ◽  
Youwei He ◽  
Yong Wang ◽  
Yulin Chen ◽  
...  
Keyword(s):  
Porous Media ◽  
Pore Structure ◽  
Structure Characterization ◽  
Flow Mechanism ◽  
Microscopic Flow

scholarly journals Petrophysical Characterization and Fractal Analysis of Carbonate Reservoirs of the Eastern Margin of the Pre-Caspian Basin

Energies ◽  
2018 ◽  
Vol 12 (1) ◽  
pp. 78 ◽  
Author(s):  
Feng Sha ◽  
Lizhi Xiao ◽  
Zhiqiang Mao ◽  
Chen Jia
Keyword(s):  
Fractal Dimension ◽  
Pore Structure ◽  
Fractal Dimensions ◽  
Core Sample ◽  
Carbonate Reservoirs ◽  
Structure Characterization ◽  
Caspian Basin ◽  
Thin Sections ◽  
Mercury Intrusion ◽  
Eastern Margin

Petrophysical properties including pore structure and permeability are essential for successful evaluation and development of reservoirs. In this paper, we use casting thin section and mercury intrusion capillary pressure (MICP) data to investigate the pore structure characterization, permeability estimation, and fractal characteristics of Carboniferous carbonate reservoirs in the middle blocks of the eastern margin of the Pre-Caspian Basin. Rock casting thin sections show that intergranular and intragranular dissolution pores are the main storage spaces. The pore throats greater than 1 μm and lower than 0.1 μm account for 47.98% and 22.85% respectively. A permeability prediction model was proposed by incorporating the porosity, Swanson, and R35 parameters. The prediction result agrees well with the core sample data. Fractal dimensions based on MICP curves range from 2.29 to 2.77 with an average of 2.61. The maximum mercury intrusion saturation is weakly correlated with the fractal dimension, while the pore structure parameters such as displacement pressure and median radii have no correlation with fractal dimension, indicating that single fractal dimension could not capture the pore structure characteristics. Finally, combined with the pore types, MICP shape, and petrophysical parameters, the studied reservoirs were classified into four types. The productivity shows a good correlation with the reservoir types.

Correlation of Pore Structure and Permeability by SEM-Image Analysis

1990 ◽  
Vol 48 (1) ◽  
pp. 428-429
Author(s):  
C. A. Callender ◽  
Wm. C. Dawson ◽  
J. J. Funk
Keyword(s):  
Image Analysis ◽  
Pore Structure ◽  
Imaging System ◽  
Pore Space ◽  
Simulation Models ◽  
Image Analyzer ◽  
Imaging Data ◽  
Sem Images ◽  
Thin Sections ◽  
Rock Types

The geometric structure of pore space in some carbonate rocks can be correlated with petrophysical measurements by quantitatively analyzing binaries generated from SEM images. Reservoirs with similar porosities can have markedly different permeabilities. Image analysis identifies which characteristics of a rock are responsible for the permeability differences. Imaging data can explain unusual fluid flow patterns which, in turn, can improve production simulation models.Analytical SchemeOur sample suite consists of 30 Middle East carbonates having porosities ranging from 21 to 28% and permeabilities from 92 to 2153 md. Engineering tests reveal the lack of a consistent (predictable) relationship between porosity and permeability (Fig. 1). Finely polished thin sections were studied petrographically to determine rock texture. The studied thin sections represent four petrographically distinct carbonate rock types ranging from compacted, poorly-sorted, dolomitized, intraclastic grainstones to well-sorted, foraminiferal,ooid, peloidal grainstones. The samples were analyzed for pore structure by a Tracor Northern 5500 IPP 5B/80 image analyzer and a 80386 microprocessor-based imaging system. Between 30 and 50 SEM-generated backscattered electron images (frames) were collected per thin section. Binaries were created from the gray level that represents the pore space. Calculated values were averaged and the data analyzed to determine which geological pore structure characteristics actually affect permeability.

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