One of the major problems during gas injection in unconventional reservoirs is asphaltene precipitation and deposition. Asphaltenes can reduce the pore throat in the reservoir and plug the surface and subsurface equipment during the production process, thus, result in oil production reduction with significant financial consequences. The impact of carbon dioxide (CO2) gas injection on asphaltene deposition in unconventional reservoirs still poorly investigated. This research investigates the impact of CO2 gas injection on asphaltene aggregation in ultra-low-permeability pore structures, mainly present in unconventional shale resources. First, the minimum miscibility pressure (MMP) of crude oil with CO2 was determined using the slim tube technique. Then, several CO2 injection pressures were selected to conduct the filtration experiments using a specially designed filtration apparatus. All pressures selected were below the MMP. Various sizes of filter paper membranes were used to study the effect of pore structure on asphaltene deposition. The results showed that asphaltene weight percent was increased by increasing the pressure and a significant asphaltene weight percentage was observed on smaller pore size structures of the filter membranes. The visualization tests revealed the process of asphaltene precipitation and deposition and showed that asphaltene particles and clusters were precipitated after one hour and fully deposited in the bottom of the test tube after 12 hours. High-resolution photos of filter paper membranes were presented using microscopy imaging and scanning electron microscopy (SEM) analysis; these photos highlighted the asphaltene particles inside the filter paper membranes and pore plugging was observed. The study's findings will contribute to a better understanding of the main factors influencing the stability of asphaltene particles in crude oil under immiscible CO2 injection pressure, particularly in nano pores, which are predominant in shale unconventional resources.
Geological storage of carbon dioxide (CO2) in depleted gas reservoirs represents a cost-effective solution to mitigate global carbon emissions. The surface chemistry of the reservoir rock, pressure, temperature, and moisture content are critical factors that determine the CO2 adsorption capacity and storage mechanisms. Shale-gas reservoirs are good candidates for this application. However, the interactions of CO2 and organic content still need further investigation. The objectives of this paper are to (i) experimentally investigate the effect of pressure and temperature on the CO2 adsorption capacity of activated carbon, (ii) quantify the nanoscale interfacial interactions between CO2 and the activated carbon surface using Monte Carlo molecular modeling, and (iii) quantify the correlation between the adsorption isotherms of activated carbon-CO2 system and the actual carbon dioxide adsorption on shale-gas rock at different temperatures and geochemical conditions. Activated carbon is used as a proxy for kerogen. The objectives aim at obtaining a better understanding of the behavior of CO2 injection and storage into shale-gas formations.
We performed experimental measurements and Grand Canonical Monte Carlo (GCMC) simulations of CO2 adsorption onto activated carbon. The experimental work involved measurements of the high-pressure adsorption capacity of activated carbon using pure CO2 gas. Subsequently, we performed a series of GCMC simulations to calculate CO2 adsorption capacity on activated carbon to validate the experimental results. The simulated activated carbon structure consists of graphite sheets with a distance between the sheets equal to the average actual pore size of the activated carbon sample. Adsorption isotherms were calculated and modeled for each temperature value at various pressures.
The adsorption of CO2 on activated carbon is favorable from the energy and kinetic point of view. This is due to the presence of a wide micro to meso pore sizes that can accommodate a large amount of CO2 particles. The results of the experimental work show that excess adsorption results for gas mixtures lie in between the results for pure components. The simulation results agree with the experimental measurements. The strength of CO2 adsorption depends on both surface chemistry and pore size of activated carbon. Once strong adsorption sites within nanoscale network are established, gas adsorption even at very low pressure is governed by pore width rather than chemical composition. The outcomes of this paper provides new insights about the parameters affecting CO2 adsorption and storage in shale-gas reservoirs, which is critical for developing standalone representative models for CO2 adsorption on pure organic carbon.
more » « less- Award ID(s):
- 1834345
- NSF-PAR ID:
- 10390693
- Date Published:
- Journal Name:
- 2022 SPE Annual Technical Conference and Exhibition
- Format(s):
- Medium: X
- Sponsoring Org:
- National Science Foundation
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Summary Asphaltene precipitation and deposition is considered one of the prevailing issues during carbon dioxide (CO2) gas injection in gas enhanced oil recovery techniques, which leads to pore plugging, oil recovery reduction, and damaged surface and subsurface equipment. This research provides a comprehensive investigation of the effect of immiscible and miscible CO2 gas injection in nanopore shale structures on asphaltene instability in crude oil. A slimtube was used to determine the minimum miscibility pressure (MMP) of the CO2. This step is important to ensure that the immiscible and miscible conditions will be achieved during the filtration experiments. For the filtration experiments, nanocomposite filter paper membranes were used to mimic the unconventional shale pore structure, and a specially designed filtration apparatus was used to accommodate the filter paper membranes. The uniform distribution (i.e., same pore size filters) was used to illustrate the influence of the ideal shale reservoir structure and to provide an idea on how asphaltene will deposit when utilizing the heterogeneous distribution (i.e., various pore size filters) that depicts the real shale structure. The factors investigated include immiscible and miscible CO2 injection pressures, temperature, CO2 soaking time, and pore size structure heterogeneity. Visualization tests were undertaken after the filtration experiments to provide a clear picture of the asphaltene precipitation and deposition process over time. The results showed an increase in asphaltene weight precent in all experiments of the filtration tests. The severity of asphaltene aggregations was observed at a higher rate under miscible CO2 injection. It was observed that the miscible conditions have a higher impact on asphaltene instability compared to immiscible conditions. The results revealed that the asphaltene deposition was almost equal across all the paper membranes for each pressure used when using a uniform distribution. Higher asphaltene weight percent were determined on smaller pore structures of the membranes when using heterogeneous distribution. Soaking time results revealed that increasing the soaking time resulted in an increase in asphaltene weight precent, especially for 60 and 120 minutes. Visualization tests showed that after 1 hour, the asphaltene clusters started to precipitate and could be seen in the uppermost section of the test tubes and were fully deposited after 12 hours with less clusters found in the supernatant. Also, smaller pore size of filter membranes showed higher asphaltene weight percent after the visualization test. Chromatography analysis provided further evaluation on how asphaltene was reduced though the filtration experiments. Microscopy and scanning electron microscopy (SEM) imaging of the filter paper membranes showed the severity of pore plugging in the structure of the membranes. This research highlights the impact of CO2 injection on asphaltene instability in crude oil in nanopore structures under immiscible and miscible conditions. The findings in this research can be used for further research of asphaltene deposition under gas injection and to scale up the results for better understanding of the main factors that may influence asphaltene aggregation in real shale unconventional reservoirs.more » « less
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The characterization of petrophysical and geomechanical properties of source rocks presents inherent challenges due to lithology heterogeneity, lamination, distribution of organic matter, and presence of fractures. Organic-rich shales also present some distinctive features that make hydrocarbon production and CO2 geological storage unique in these rocks. The objective of this paper is to quantify and model the deformational behavior of carbon-based compounds due to changes of stress and pressure that happen simultaneously with gas adsorption and desorption processes. We designed an experimental procedure that consists of: (1) compaction of organic-rich grains/powder under oedometric conditions, (2) measurement of poromechanical properties in the absence of adsorption effects using helium in a triaxial cell through independent changes of confining pressure and pore pressure, (3) measurement of the adsorption strain, and stress for methane (CH4). An adsorptive-poromechanical model permits explaining the experimental data, discriminating between the strain/stress caused by poroelastic response from the adsorption-induced strain/stress, and measuring the poroelastic-sorption properties of the organic-rich compound. We applied this procedure to activated carbon and measured skeletal volumetric modulus ranging from 11.8 to 16.6 GPa and skeletal adsorption stress of ~100 MPa for CH4 at 7 MPa of adsorbate pressure. The proposed procedure and model are useful to explain and predict the unique properties of carbon-based adsorbents which can be extended to kerogen, a critical component in source rocks.
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null (Ed.)An original methodology is suggested for evaluating the pore size distribution in carbons in the wide range of micro- and mesopores from 0.385 to 10 nm from a single isotherm of high-pressure adsorption of CO2 at 273 K. The proposed method is based on the reference theoretical isotherms calculated by Monte Carlo simulations in model pores of slit and cylindrical geometry. The relationship between the pore size and the pore filling pressure is established. Special attention is given to predicting of the capillary condensation transitions in mesopores by using the meso-canonical ensemble (gauge cell) Monte Carlo simulations. The proposed technique is demonstrated and verified against the conventional N2 and Ar low temperature adsorption methods drawing on the example of micro-mesoporous carbons of the CMK family. Advantages and limitations of CO2 adsorption characterization of nanoporous materials are discussed and further improvements are proposed.more » « less
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ABSTRACT: The chemo-mechanical loading of rocks causes the dissolution and precipitation of multiple phases in the rock. This dissolution and precipitation of load-bearing mineral phases lead to the stress redistribution in neighboring phases, which in turn results in deformational changes of the sample composite. The aim of this study is to investigate the link between microstructural evolution and creep behavior of shale rocks subjected to chemo-mechanical loading through modeling time-dependent deformation induced by the dissolution-precipitation process. The model couples the microstructural evolution of the shale rocks with the stress/strain fields inside the material as a function of time. The modeling effort is supplemented with an experimental study where shale rocks were exposed to CO2-rich brine under high temperature and pressure conditions. 3D snapshots of the sample microstructure were generated using segmented micro-CT images of the shale sample. The time-evolving microstructures were then integrated with the Finite element-based mechanical model to simulate the creep induced by dissolution and precipitation processes independent of the intrinsic viscoelasticity/viscoplasticity of the mineral phases. After computation of the time-dependent viscoelastic properties of the shale composite, the combined microstructure model and finite element model were utilized to predict the time-dependent stress and strain fields in different zones of reacted shale.
1. INTRODUCTION Determination of viscous behavior of shale rocks is key in wide range of applications such as stability of reservoirs, stability of geo-structures subjected to environmental forcing, underground storage of hazardous materials and hydraulic fracturing. Short-term creep strains in hydraulic fracturing can change stress fields and in turn can impact the hydraulic fracturing procedures(H. Sone & Zoback, 2010; Hiroki Sone & Zoback, 2013). While long-term creep strains can hamper the reservoir performance due to the reduction in permeability of the reservoir by closing of fractures and fissures(Du, Hu, Meegoda, & Zhang, 2018; Rybacki, Meier, & Dresen, 2016; Sharma, Prakash, & Abedi, 2019; Hiroki Sone & Zoback, 2014). Owing to these significance of creep strain, it is important to understand the viscoelastic/viscoplastic behavior of shales.
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Accepted Manuscript1.0
- Conference Paper:
- https://doi.org/10.2118/210264-MS
