Application of Gamma-Alumina Nanoparticles to Enhance Spontaneous Imbibition in Low Permeable, Oil-Wet Carbonate Rocks

2018 ◽  
Author(s):  
A. Keykhosravi ◽  
M. Simjoo
Keyword(s):  
Carbonate Rocks ◽  
Spontaneous Imbibition ◽  
Alumina Nanoparticles ◽  
Gamma Alumina

Modeling the Effect of Reduced Liquid-Wetting on Spontaneous Imbibition for Condensate Blocking Applications

2012 ◽  
Author(s):  
Nour El Cheikh Ali ◽  
Mahmoud Abouseida ◽  
Mashhad Fahes
Keyword(s):  
Numerical Modeling ◽  
Carbonate Rocks ◽  
Capillary Forces ◽  
Experimental Results ◽  
Spontaneous Imbibition ◽  
Altered Rock ◽  
Liquid Saturation ◽  
Expected Result ◽  
Condensate Blocking

In this paper, we present our interpretation for some of the unexpected experimental results that we obtained during 3D spontaneous imbibition experiments. We treated carbonate rocks with flourochemical polymers where we altered the wettability towards reduced liquid-wetting. The expected result is a reduced imbibition rate as a result of reduced capillary forces. Although the early imbibition rate decreased, we observed an increase in rate at late imbibition time resulting in a higher liquid saturation in the altered rock. We used numerical modeling to interpret the result and show that this observation actually represents the target wettability state we should be seeking in some applications.

Technetium retention by gamma alumina nanoparticles and the effect of sorbed Fe2+

2020 ◽  
Vol 388 ◽  
pp. 122066
Author(s):  
Natalia Mayordomo ◽  
Diana M. Rodríguez ◽  
Dieter Schild ◽  
Konrad Molodtsov ◽  
Erik V. Johnstone ◽  
...  
Keyword(s):  
Alumina Nanoparticles ◽  
Gamma Alumina

scholarly journals Pore Structure and Connectivity of Mixed Siliciclastic-Carbonate Tight Reservoirs in the Palaeogene from Qaidam Basin, NW China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-20
Author(s):  
Xin Wang ◽  
Jianhui Zeng ◽  
Kunyu Wu ◽  
Xiangcheng Gao ◽  
Yibo Qiu ◽  
...  
Keyword(s):  
Spatial Distribution ◽  
Pore Structure ◽  
Carbonate Rocks ◽  
Qaidam Basin ◽  
Spontaneous Imbibition ◽  
Throat Radius ◽  
Number Range ◽  
X Ray ◽  
Tight Reservoirs ◽  
Intercrystalline Pores

The pore structure and connectivity in petroleum reservoirs are controlled in part by their petrological properties. Mixed siliciclastic-carbonate rocks have complex compositions and heterogeneous spatial distributions of the various minerals. As a result, the study of the pore structure and connectivity of mixed siliciclastic-carbonate tight reservoirs has been limited. In this study, methods such as thin section microscopy, X-ray diffraction, X-ray computed tomography, low pressure N2 adsorption, and spontaneous imbibition were adopted to comprehensively analyze the petrological properties, pore structure, and connectivity of the mixed siliciclastic-carbonate tight reservoirs in the upper member of the Xiaganchaigou Formation in the Yingxi Area, Qaidam Basin. The results showed that micrometer-sized pores in mixed siliciclastic-carbonate tight reservoirs are mainly dissolution pores, and that the spatial distribution of the pores is highly heterogeneous. The average pore radius range, average throat radius range, and average coordination number range of micronmeter-sized pores are 2.09~3.42 μm, 1.32~2.19 μm, and 0.48~1.49, respectively. Restricted by the concentrated distribution of local anhydrite, the connectivity of micronmeter-sized pores develops well only in the anhydrite, showing negligible contribution to the overall reservoir connectivity. In contrast, nanometer-sized pores in the mixed siliciclastic-carbonate tight reservoirs are mainly intercrystalline pores in dolomite. The range of nanometer-sized pores diameters is mainly distributed in 1.73-31.47 nm. The pores have a smooth surface, simple structure, and relatively homogeneous spatial distribution. The dissolution of dolomite intercrystalline pores by acidic fluids increases the connectivity of the nanometer-sized pores. This paper presents genetic models for microscopic pore structures and connectivity of mixed siliciclastic-carbonate rocks, making possible the evaluation on the quality of the mixed siliciclastic-carbonate tight reservoirs.

An Experimental Study on Interactions Between Imbibed Fracturing Fluid and Organic-Rich Tight Carbonate Source Rocks

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2133-2146 ◽  
Author(s):  
Feng Liang ◽  
Bitao Lai ◽  
Jilin Zhang ◽  
Hui-Hai Liu ◽  
Weichang Li
Keyword(s):  
Carbonate Rocks ◽  
Mineral Dissolution ◽  
Spontaneous Imbibition ◽  
Source Rocks ◽  
Elemental Distribution ◽  
Fluid Level ◽  
Fluid Uptake ◽  
Before And After ◽  
Tight Carbonate ◽  
Carbonate Source

Summary Carbonate reservoirs dominate oil (70%) and gas (90%) reserves in the Middle East, and imbibition is the main mechanism for fracturing-fluid uptake during the hydraulic-fracturing stimulation process. Because of the highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand the effects of imbibed fluid on the mechanical, morphological, and flow properties of carbonate rocks. Although the influence of imbibed fluids on the wettability of carbonate reservoir has been studied extensively, research regarding the effects of imbibed fluids on the texture and mineralogy of carbonate rocks is still very limited. This paper aims to provide a conceptual approach and work flow to characterize and quantify microstructure and mineralogy changes in carbonate rocks caused by imbibed fluids. A thin section of a low-permeability organic-rich carbonate-rock sample [7×7×0.3 mm (length×width×thickness)] was used in the study. The sample was submerged into 2%-KCl (pH = 7.1) fluid from one end to simulate the spontaneous-imbibition process. A scanning electron microscope (SEM) was used to capture the sample's morphological changes before and after spontaneous imbibition. Energy-dispersive-spectroscopy (EDS) maps were measured before and after fluid treatment to investigate changes in various elemental distribution. In addition, inductively coupled plasma (ICP) equipped with an optical-emission-spectrometer (OES) detector was used to quantify dissolved-ion concentration in the treatment fluid. Permeability and porosity were measured using core plugs with dimensions of 1.0×1.5 in. (diameter×length) before and after fluid treatment. During the imbibition process, approximately one-half of the sample was submerged in the treatment fluid. The SEM images for the thin-section sample showed three zones with distinct fluid-uptake characteristics. In Zone I, which was fully submerged in the testing fluid, a significant amount of mineral dissolution was observed. In Zone III, which was above the testing-fluid level, considerable mineral precipitation was detected. While in the transition zone just above the water/air interface (Zone II between the previous two zones), only a minor level of mineral dissolution was observed. Elemental-distribution changes resulting from the fluid treatment were identified by EDS analysis in all three zones. Gypsum and calcite crystals dissolved into imbibed fluids upon reaction. Gypsum was found reprecipitated on the rock surface in the zones above fluid level. The observed gypsum formation likely resulted from the dissolution of the gypsum from the rock matrix, then reprecipitation later from the imbibition experiment caused by water evaporation. Absolute-permeability and porosity measurements for core-plug samples have shown that both were increased after the imbibition process.

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