scholarly journals A technique to identify the predominant pore direction in a porous medium and application to reservoir rocks

2021 ◽  
Author(s):  
Waldir L. Roque ◽  
Edvaldo F. M. Neto ◽  
José V. P. Cruz Júnior
Keyword(s):  
Porous Medium ◽  
Bone Structure ◽  
Pore Space ◽  
Binary Image ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Berea Sandstone ◽  
Pore Networks ◽  
Sandstone Rock ◽  
2D And 3D

AbstractThe study of the pore space structure of a porous medium has been very much improved with the aid of microtomographic imaging and its analysis through image processing. In this paper, a technique to identify the predominant pore direction (PPD) in the pore space is introduced and according to that the pore space can be partition as vertical (V), horizontal (H) or diagonal (D). The PPD technique has been developed for 2D and 3D spaces based on microCT images of a porous medium and can be used to both, pore or grain spaces. An implementation of the PPD has been done in an in-house computer program using Phyton. A set of application tests for 2D and 3D PPD partitioning is given, being, respectively, i) a synthetic binary image and a binary image of a Berea sandstone rock sample and ii) a Berea sandstone and a Carbonate reservoir rock core samples, both provided by the MicroCT Images and Networks of Imperial College London database, and a 3D grain partitioning of a trabecular bone structure. Additionally, the V, H and D PPD effective pore networks of a pore space are determined; the porosities for the PPD subspaces and for their effective pore networks are computed and results are provided. Finally, a brief discussion about the implementation and computational cost for the 2D and 3D cases is provided. It is worth to mention that the findings of this study may help for better understanding of directional fluid flow and mechanical stress in porous medium.

scholarly journals Pore Structure Characteristics of Tight Carbonate Reservoir in Qingxi Sag, Jiuquan Basin

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Xiangye Kong ◽  
Jianhui Zeng ◽  
Xianfeng Tan ◽  
Xianglu Gao ◽  
Yu Peng ◽  
...  
Keyword(s):  
Pore Structure ◽  
Tube Bundle ◽  
Pore Space ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Tight Oil ◽  
Type I ◽  
Structure Characteristics ◽  
Small Pore ◽  
Tight Carbonate

Abstract The Xiagou Formation is the main tight oil reservoir in Qingxi Sag of Jiuquan Basin. Given the poor physical properties and other factors restricting tight oil exploitation and production in this area, studies should focus on microscopic pore structure characteristics. In this study, a nano-CT scanner, a SEM, and an NMR were used to study the pore structure characteristics of a tight carbonate reservoir in Qingxi Sag, Jiuquan Basin. The Xiagou Formation reservoir mainly consists of gray argillaceous dolomite and dolomitic mudstone. The pore categories are mainly elliptic, irregular, intergranular, and intragranular and mostly filled with clay and carbonate cement. Pore space is small, the intergranular or organic pores are mostly separated, and pore-throat is weakly connected. The throats mostly develop with lamellar and tube bundle-like characteristics and with poor seepage ability. The pore-throats mostly span from nanometer to micrometer sizes, and pore diameters are mainly concentrated in the range of 0.01–0.1 and 1–10 μm. It is a unimodal pattern mainly composed of micropores, or a bimodal regular allocation dominated by micropores supplemented by macropores. The relationship between micropore (<0.1 μm) and macropore (>1 μm) content allocation and mean pore diameter strongly controls the permeability of reservoir rocks. When macropore content reaches more than 85%, or when pore content totals less than 3%, the permeability of a reservoir remarkably increases. At a higher ratio of the average finest throat sectional area and throat-pore of reservoir rock, the throat radius lies closer to the connecting pore radius, pore and throat connectivity improves, and reservoir seepage ability becomes stronger. Based on reservoir capacity and seepage ability, pore structures of the tight carbonate reservoirs in study area are classified into type I (small-pore–thin-throat), type II (thin-pore–thin-throat), and type III (microporous-microthroat) with rock permeability>0.1 mD, 0.05–0.1 mD, and <0.05 mD, respectively. The type I pore structure reservoir should be regarded as an indicator of tight oil “sweet spots” reservoir in the study area.

Low Polymer Retention Possible in Flooding of High-Salinity Carbonate Reservoirs

2021 ◽  
Vol 73 (11) ◽  
pp. 60-61
Author(s):  
Chris Carpenter
Keyword(s):  
Porous Medium ◽  
High Salinity ◽  
Material Balance ◽  
Synthetic Polymers ◽  
Polymer Flooding ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Abu Dhabi ◽  
Polymer Retention

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202809, “Low Polymer Retention Opens for Field Implementation of Polymer Flooding in High-Salinity Carbonate Reservoirs,” by Arne Skauge, SPE, and Tormod Skauge, SPE, Energy Research Norway, and Shahram Pourmohamadi, Brent Asmari, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Polymer flooding has been a successful enhanced-oil-recovery method in sandstone reservoirs for decades. Extending polymer flooding to carbonate reservoirs has been challenging because of adsorption loss and polymer availability for high-temperature, high-salinity (HT/HS) reservoirs. In this study, the authors establish that HT/HS polymers can exhibit low adsorption and retention in carbonate reservoir rock at ultrahigh salinity conditions. Introduction Retention is a key factor for polymer propagation and acceleration of oil production by polymer flooding. In the complete paper, the authors consider HT/HS applications for carbonate reservoirs. Synthetic polymers such as partially hydrolyzed polyacrylamide are not thermally stable at temperatures above 60°C. The thermal stability of the synthetic polymers can be improved by incorporating monomers. To evaluate the retention of polymer in reservoir rock, dynamic retention experiments were performed in the presence and absence of oil. In homogeneous rock, the presence of residual oil typically will reduce the retention proportional to the surface covered by the oil saturation. Strongly heterogeneous rock containing fractures also may have low retention because the fluid flow mainly may be through highly permeable fractures or channels and, consequently, only part of the porous medium will contact polymer. Retention in carbonate matrix displacement (homogeneous rock) was performed on outcrop Indiana limestone for reference, but most experiments were made on reservoir rock material. The polymer used is SAV 10. Experimental Methods The easiest and, in many cases, most-accurate method for quantifying retention in dynamic coreflow experiments is by material balance. This refers to the measurement of the polymer in the effluent. The injected amount minus the backproduced amount of polymer gives the loss caused by transport through the porous medium. The retention includes both adsorption of polymer onto the rock and dynamic loss as the result of mechanical entrapment such as molecular straining and concentration blocking. In most cases, the authors used a passive tracer injected with the polymer and applied two slugs. The first slug quantifies the retention by material balance, but the difference in effluent of the second slug minus the first slug also can give an alternative measurement of the polymer retention. Comparing tracer and polymer effluent concentrations from the second polymer slug quantifies the inaccessible pore volume (IPV). The experimental setup is illustrated in Fig. 1.

Predicted Liquid Water Saturation in Unstructured Pore Networks Based on PEMFC GDL Porosity Profiles

2010 ◽  
Author(s):  
J. Hinebaugh ◽  
Z. Fishman ◽  
A. Bazylak
Keyword(s):  
Liquid Water ◽  
Water Saturation ◽  
Pore Space ◽  
Polymer Electrolyte Membrane ◽  
Gas Diffusion ◽  
Pore Network Model ◽  
High Porosity ◽  
Pore Networks ◽  
Electrolyte Membrane ◽  
Capillary Pressures

An unstructured, two-dimensional pore network model is employed to describe the effect of through-plane porosity profiles on liquid water saturation within the gas diffusion layer (GDL) of the polymer electrolyte membrane fuel cell. Random fibre placements are based on the porosity profiles of six commercially available GDL materials recently obtained through x-ray computed tomography experiments. The pore space is characterized with a Voronoi diagram, and invasion percolation-based simulations are performed. It is shown that water tends to accumulate in regions of relatively high porosity due to the lower associated capillary pressures. It is predicted that GDLs tailored to have smooth porosity profiles will have fewer pockets of high saturation levels within the bulk of the material.

Needles in the Pay Stack ADNOC Exploring Tight-Oil Rock, Triples Production In First Pilot

2021 ◽  
Vol 73 (01) ◽  
pp. 20-22
Author(s):  
Trent Jacobs
Keyword(s):  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Abu Dhabi ◽  
Data Set ◽  
Slowing Down ◽  
Tight Carbonate ◽  
Potential Impact ◽  
Carbonate Formations ◽  
Oil Company ◽  
Term Data

In the midst of an industry downturn last year, the Abu Dhabi National Oil Company (ADNOC) reached a new oil production ceiling of 4 million B/D. The UAE’s largest producer has no intentions of slowing down. By decade’s end, ADNOC expects to have raised its maximum daily output by another million barrels. To cross that milestone, the company has set its sights on mastering the tight, thin, and unconventional formations that dot the UAE’s subsurface landscape. One of the places where such developments are hoped to unfold soon is known as Field Q. Found in southeastern Abu Dhabi, Field Q sits above a tight carbonate reservoir that holds an estimated 600 million bbl of oil. But with a permeability ranging from 1 to 3 millidarcy and poor vertical communication, the reservoir and its barrels have proven difficult to cultivate economically - until recently. ADNOC has published new details of its first onshore pilot of a “fishbone stimulation” that involved using more than a hundred hollow needles to pierce as far as 40 ft into the reservoir rock. The additional drainage netted by the fishbone needles boosted production threefold in the test well, as compared with its traditionally completed neighbors on the same pad. ADNOC ran the pilot in the summer of 2019 and by the end of the year saw enough production data to launch a wider 10-well pilot that remains underway. Based on a longer-term data set from these wells, the company will decide whether to leap into a fieldwide deployment of the niche completions technology. In the meantime, the petrotechnical team in charge of the test projects have issued roundly positive reviews of the fishbone technique in two recently presented technical papers (SPE 202636; SPE 203086) from the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC). “There is a chance that the fishbone-stimulated wells can avoid the drilling of multiple wells targeting different sublayers in the same zone,” said Rama Rao Rachapudi, listing one of several of the technology’s advantages over other approaches that were considered. The senior petroleum engineer with ADNOC, who is one of several authors of the papers that cover both the drilling and completions aspects of the pilot, shared during ADIPEC that his onshore team found motivation to test the technology after bringing in a batch of dis-mal appraisal wells. The fishbone system, also known as multilateral jetting stimulation technology, has been a specialized application ever since it was introduced just over a decade ago. Underscoring the potential impact of the current round of pilots on the technology’s adoption rate, ADNOC noted there were only around 30 worldwide fishbone deployments prior to this project. Most of those have been in the Middle East’s naturally fractured and layered carbonate formations - just like those of Field Q.

scholarly journals Transport Simulations on Scanning Transmission Electron Microscope Images of Nanoporous Shale

Energies ◽  
2020 ◽  
Vol 13 (24) ◽  
pp. 6665
Author(s):  
Laura Frouté ◽  
Yuhang Wang ◽  
Jesse McKinzie ◽  
Saman Aryana ◽  
Anthony Kovscek
Keyword(s):  
Gas Permeability ◽  
Pore Space ◽  
Knudsen Diffusion ◽  
Transport Processes ◽  
Pore Scale ◽  
Pore Networks ◽  
Scanning Transmission Electron ◽  
Transmission Electron ◽  
Scanning Transmission ◽  
Stem Tomography

Digital rock physics is an often-mentioned approach to better understand and model transport processes occurring in tight nanoporous media including the organic and inorganic matrix of shale. Workflows integrating nanometer-scale image data and pore-scale simulations are relatively undeveloped, however. In this paper, a workflow is demonstrated progressing from sample acquisition and preparation, to image acquisition by Scanning Transmission Electron Microscopy (STEM) tomography, to volumetric reconstruction to pore-space discretization to numerical simulation of pore-scale transport. Key aspects of the workflow include (i) STEM tomography in high angle annular dark field (HAADF) mode to image three-dimensional pore networks in µm-sized samples with nanometer resolution and (ii) lattice Boltzmann method (LBM) simulations to describe gas flow in slip, transitional, and Knudsen diffusion regimes. It is shown that STEM tomography with nanoscale resolution yields excellent representation of the size and connectivity of organic nanopore networks. In turn, pore-scale simulation on such networks contributes to understanding of transport and storage properties of nanoporous shale. Interestingly, flow occurs primarily along pore networks with pore dimensions on the order of tens of nanometers. Smaller pores do not form percolating pathways in the sample volume imaged. Apparent gas permeability in the range of 10−19 to 10−16 m2 is computed.

scholarly journals The transport of liquids in softwood: timber as a model porous medium

2019 ◽  
Vol 9 (1) ◽  
Author(s):  
H. C. Burridge ◽  
G. Wu ◽  
T. Reynolds ◽  
D. U. Shah ◽  
R. Johnston ◽  
...  
Keyword(s):  
Experimental Data ◽  
Porous Medium ◽  
Fluid Flow ◽  
Transport Properties ◽  
Pore Space ◽  
Construction Material ◽  
Sustainable Construction ◽  
Natural Material ◽  
Full Potential ◽  
Treatment Processes

AbstractTimber is the only widely used construction material we can grow. The wood from which it comes has evolved to provide structural support for the tree and to act as a conduit for fluid flow. These flow paths are crucial for engineers to exploit the full potential of timber, by allowing impregnation with liquids that modify the properties or resilience of this natural material. Accurately predicting the transport of these liquids enables more efficient industrial timber treatment processes to be developed, thereby extending the scope to use this sustainable construction material; moreover, it is of fundamental scientific value — as a fluid flow within a natural porous medium. Both structural and transport properties of wood depend on its micro-structure but, while a substantial body of research relates the structural performance of wood to its detailed architecture, no such knowledge exists for the transport properties. We present a model, based on increasingly refined geometric parameters, that accurately predicts the time-dependent ingress of liquids within softwood timber, thereby addressing this long-standing scientific challenge. Moreover, we show that for the minimalistic parameterisation the model predicts ingress with a square-root-of-time behaviour. However, experimental data show a potentially significant departure from this $$\sqrt{{\boldsymbol{t}}}$$t behaviour — a departure which is successfully predicted by our more advanced parametrisation. Our parameterisation of the timber microstructure was informed by computed tomographic measurements; model predictions were validated by comparison with experimental data. We show that accurate predictions require statistical representation of the variability in the timber pore space. The collapse of our dimensionless experimental data demonstrates clear potential for our results to be up-scaled to industrial treatment processes.

Simultaneous Interpretation of Three-Phase Relative Permeability and Capillary Pressure for a Tight Carbonate Reservoir From Wireline Formation Testing

2019 ◽  
Vol 142 (6) ◽  
Author(s):  
Xiangnan Liu ◽  
Daoyong Yang
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
History Matching ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Fluid Saturation ◽  
Three Phase ◽  
Tight Carbonate ◽  
Wet Condition ◽  
Oil Gas

Abstract In this paper, techniques have been developed to interpret three-phase relative permeability and water–oil capillary pressure simultaneously in a tight carbonate reservoir from numerically simulating wireline formation tester (WFT) measurements. A high-resolution cylindrical near-wellbore model is built based on a set of pressures and flow rates collected by dual packer WFT in a tight carbonate reservoir. The grid quality is validated, the effective thickness of the WFT measurements is examined, and the effectiveness of the techniques is confirmed prior to performing history matching for both the measured pressure drawdown and buildup profiles. Water–oil relative permeability, oil–gas relative permeability, and water–oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined using the modified Stone II model. Both the relative permeability and the capillary pressure of a water–oil system interpreted under an oil-wet condition match well with the measured relative permeability and capillary pressure of a similar reservoir rock type collected from the literature, while the relative permeability of an oil–gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the reservoir determined as oil-wet but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water–oil relative permeabilities.

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