A microscopic characterization of wettability in shale kerogen with varying maturity levels

Hu, Yinan; Devegowda, Deepak; Sigal, Richard F.

doi:10.1016/j.jngse.2016.06.014

Cited by 97 publications

(81 citation statements)

References 37 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Mechanistically, shale pore networks comprise of (a) inorganic porosity (clay and nonclay minerals) and (b) organic matter porosity where the organic pores are hydrophobic while the inorganic pores are hydrophilic [ Curtis et al ., ]. Thus, the composite wetting behavior of shale is controlled by the distribution and connectivity of organic and inorganic matter [ Hu et al ., ]. Consequently, the CO 2 ‐wet nature of high‐TOC samples (shales C and D) indicates that organic matter dominates the composite wetting behavior, while the water‐wet behavior of low TOC shale indicates mineral dominance in pore spaces.…”

Section: Resultsmentioning

confidence: 99%

Influence of shale‐total organic content on CO₂ geo‐storage potential

Arif

Lebedev

Barifcani

et al. 2017

Geophysical Research Letters

121

View full text Add to dashboard Cite

Shale CO2 wettability is a key factor which determines the structural trapping capacity of a caprock. However, the influence of shale‐total organic content (TOC) on wettability (and thus on storage potential) has not been evaluated despite the fact that naturally occurring shale formations can vary dramatically in TOC, and that even minute TOC strongly affects storage capacities and containment security. Thus, there is a serious lack of understanding in terms of how shale, with varying organic content, performs in a CO2 geo‐storage context. We demonstrate here that CO2‐wettability scales with shale‐TOC at storage conditions, and we propose that if TOC is low, shale is suitable as a caprock in conventional structural trapping scenarios, while if TOC is ultrahigh to medium, the shale itself is suitable as a storage medium (via adsorption trapping after CO2 injection through fractured horizontal wells).

show abstract

Section: Resultsmentioning

confidence: 99%

Influence of shale‐total organic content on CO₂ geo‐storage potential

Arif

Lebedev

Barifcani

et al. 2017

Geophysical Research Letters

121

View full text Add to dashboard Cite

show abstract

“…Some experts believe that the fracturing fluid is imbition into the complex fracture network area, and the mechanisms of oil recovery after hydraulic fracturing are imbibition [9]. The evaluation of fracturing fluid effect and the theoretical model of imbibition have gradually become a research focus [10][11][12][13][14][15][16][17][18][19]. Meng et al [5] explained that the rock fracture pressure is high during hydraulic fracturing, the fracture stress after fracturing is obviously higher than the matrix pressure.…”

Section: Introductionmentioning

confidence: 99%

Frontier Enhanced Oil Recovery (EOR) Research on the Application of Imbibition Techniques in High-Pressure Forced Soaking of Hydraulically Fractured Shale Oil Reservoirs

Guo

et al. 2021

Geofluids

View full text Add to dashboard Cite

Shale reservoirs are characterized by low porosity and low permeability, and volume fracturing of horizontal wells is a key technology for the benefits development of shale oil resources. The results from laboratory and field tests show that the backflow rate of fracturing fluid is less than 50%, and the storage amount of fracturing fluid after large-scale hydraulic fracturing is positively correlated with the output of single well. The recovery of crude oil is greatly improved by means of shut-in and imbibition, therefore attracting increasing attention from researchers. In this review, we summarize the recent advances in the migration mechanisms and stimulation mechanisms of horizontal well high pressure forced soaking technology in the reservoirs. However, due to the diversity of shale mineral composition and the complexity of crude oil composition, the stimulation mechanism and effect of this technology are not clear in shale reservoir. Therefore, the mechanism of enhanced oil recovery by imbibition and the movable lower limit of imbibition cannot be characterized quantitatively. It is necessary to solve fragmentation research in the full-period fluid transport mechanisms in the follow-up research.

show abstract

“…Kerogen is classified by its chemical composition, and the C/O ratio 34−36 is one of the parameters frequently used to quantify the degree of maturity. 37 Different kerogen models have been proposed, 38,39 considering the C/O ratio varying from 0.03 to 0.2, depending on the specific kerogen. Within these models, oxygens mainly belong to carboxylic (−COOH) and carbonyl (>CO) groups.…”

Section: Introductionmentioning

confidence: 99%

“…On the other hand, there are several molecular models for kerogen’s microporosity available in the literature. , However, nanoscale models of these materials are not fully developed. Kerogen is classified by its chemical composition, and the C/O ratio − is one of the parameters frequently used to quantify the degree of maturity . Different kerogen models have been proposed, , considering the C/O ratio varying from 0.03 to 0.2, depending on the specific kerogen.…”

Section: Introductionmentioning

confidence: 99%

Diminished Fluid Transport through Carbon Nanochannels Induced by COOH Functionalization: Implications for Nanofiltration and Oil Recovery

Sánchez

Castez

Winograd³

2021

ACS Appl. Nano Mater.

View full text Add to dashboard Cite

Fluid transport on confined systems is a subject of theoretical and technological interest. For instance, remarkable high flow rates have been obtained in carbon nanochannels (CNs) which cannot be predicted by standard macroscopic theories. Natural rocks, which are at the heart of the shale hydrocarbon revolution, may also exhibit similar properties as the porous structure is mainly at the nanoscale and is carbon rich. Among other differences with CNs, the surfaces are not atomically smooth, as they have organic functional groups anchored on their inner porous surfaces. In this work, we assess the effects of carboxylic functionalization of the nanochannel surfaces on fluid transport. We consider water and methane as representative cases for polar/ non-polar fluids and also mixtures of them. We find that the presence of only a few carboxylic groups on the CN causes a large reduction of flow rates for all fluids considered due to the associated geometrical distortion. However, for water, the hydrophilicity induced by the carboxylic functionalization causes not only a dramatic reduction in flow rates but also structural changes in which COOH groups act as nucleation centers for water droplets. Implications of our results show that the flow rates depend on the O/C ratio of the nanochannel, which is a measure of kerogen maturity. The relationship between rock permeability and maturity may provide a way to identify high conductive zones for hydrocarbon recovery. Another application is the possible use of chemical additives to enhance hydrocarbon flow on kerogen-rich rocks. The presence of a small amount of scattered organic functional groups in the nanochannel helps to distribute water molecules along the nanochannel walls, opening a path for hydrocarbon to flow.

show abstract

A microscopic characterization of wettability in shale kerogen with varying maturity levels

Cited by 97 publications

References 37 publications

Influence of shale‐total organic content on CO₂ geo‐storage potential

Influence of shale‐total organic content on CO₂ geo‐storage potential

Frontier Enhanced Oil Recovery (EOR) Research on the Application of Imbibition Techniques in High-Pressure Forced Soaking of Hydraulically Fractured Shale Oil Reservoirs

Diminished Fluid Transport through Carbon Nanochannels Induced by COOH Functionalization: Implications for Nanofiltration and Oil Recovery

Contact Info

Product

Resources

About

A microscopic characterization of wettability in shale kerogen with varying maturity levels

Cited by 97 publications

References 37 publications

Influence of shale‐total organic content on CO2 geo‐storage potential

Influence of shale‐total organic content on CO2 geo‐storage potential

Frontier Enhanced Oil Recovery (EOR) Research on the Application of Imbibition Techniques in High-Pressure Forced Soaking of Hydraulically Fractured Shale Oil Reservoirs

Diminished Fluid Transport through Carbon Nanochannels Induced by COOH Functionalization: Implications for Nanofiltration and Oil Recovery

Contact Info

Product

Resources

About

Influence of shale‐total organic content on CO₂ geo‐storage potential

Influence of shale‐total organic content on CO₂ geo‐storage potential