The wettability of shale by NMR measurements and its controlling factors

Su, Siyuan; Jiang, Zhenxue; Shan, Xuanlong; Zhu, Yunfeng; Wang, Peng; Luo, Xuan; Zheng, Li; Zhu, Rixiang; Wang, Xiaoyong

doi:10.1016/j.petrol.2018.05.067

Cited by 54 publications

(16 citation statements)

References 16 publications

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“…The key advantage of SI is that it can assess mixed-wettability behavior of shale surfaces for shale/brine/oil systems, while for a shale/CO 2 /brine system forced imbibition may be required which is challenging, especially at high pressure. Wettability characterization using NMR is based on the relative water absorption and oil absorption capacities of brine-saturated and oil-saturated core samples, respectively. , While NMR spectroscopy is an attractive technique in terms of quantitative evaluation of shale wettability, one key disadvantage is that NMR requires separation of the wetting and nonwetting phase signals and information about the pore size distribution . The contact angle method, which is the focus of this review, is discussed in more detail below.…”

Section: Wettability Assessment Methodsmentioning

confidence: 99%

“…Thus, it is clear that a precise evaluation of shale wettability is extremely important for successful hydrocarbon exploitation from shale reservoirs. Currently, the contact angle method is frequently used to measure shale wettability under different operating conditions, ,− while spontaneous imbibition has also been extensively studied recently, − and some NMR investigations have been conducted. , However, only a few studies have used molecular dynamics simulations to examine shale wettability. , One key factor that limits the understanding of shale rocks is their complex microstructure, ,− including organic matter, minerals, and microfractures. ,, Consequently, a precise shale wettability characterization may not be possible without a detailed understanding of the associated shale microstructure. Furthermore, no single imaging technique is capable to capture the shale rock microstructure fully and accurately, rather a multiscale correlative imaging approach is required. ,, …”

Section: Introductionmentioning

confidence: 99%

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Shale Wettability: Data Sets, Challenges, and Outlook

2021

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The wetting characteristics of shale rocks at representative subsurface conditions remain an area of active debate. A precise characterization of shale wettability is essential for enhanced oil and gas recovery, containment security during CO 2 geo-storage, and flow back efficiency during hydraulic fracturing. While several methods were utilized in the literature to evaluate shale wettability (e.g., contact angle measurements, spontaneous imbibition method ,and NMR method), we here review the recently published data sets on shale contact angle measurements. The objectives of this review are to (a) develop a repository of the recent shale wettability data sets using contact angle measurements at high pressure and temperature (HPHT) conditions, (b) explore the factors influencing shale wettability, (c) identify potential limitations associated with contact angle methods, and (d) provide a research outlook for this area. On the basis of the data reviewed here, we conclude the following: (1) Shale/oil/brine systems demonstrate water-wet to strongly oil-wet wetting behaviors. (2) Shale/CO 2 /brine systems are usually weakly water-wet to CO 2 -wet. (3) Shale/CH 4 /brine systems are weakly water-wet. The key contributing factors that underpin this high shale wettability variability include, but are not limited to, operating pressure and temperature conditions, total organic content (TOC), mineral matter, and thermal maturity conditions. Thus, this review provides a succinct analysis of the shale wettability contact angle data sets and affords an overview of the current state of the art technology and possible future developments in this area to enhance the understanding of shale wettability.

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Section: Wettability Assessment Methodsmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Shale Wettability: Data Sets, Challenges, and Outlook

2021

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“…Displacing water from clay‐associated pores will thus be very difficult, so we suggest that gas will only move through these pores if they have been dehydrated over geological time due to dissolution of water into generated gas. For oil especially, the wetting state of each part of the pore system is also a key factor for two phase flow but is poorly constrained in mudstones; we might reasonably assume that OM is oil‐wet, but the wetting state of the clay matrix is unknown (e.g., Aplin & Larter, ; Kibria et al, ; Su et al, ).…”

Section: Discussionmentioning

confidence: 99%

Influence of Clay, Calcareous Microfossils, and Organic Matter on the Nature and Diagenetic Evolution of Pore Systems in Mudstones

et al. 2019

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Mudstones exert a fundamental control on the flow of both aqueous and nonaqueous fluids in sedimentary basins. Predicting their flow and storage properties requires an understanding of pore size and connectivity, yet there are very few quantitative descriptions of pore systems of mineralogically and texturally well-characterized mudstones. We use a combination of electron microscopy, mercury injection capillary pressure porosimetry, and CO 2 sorption methods to generate a quantitative description of the size distribution, connectivity, and evolution of pore systems in a sequence of Posidonia Shale mudstones buried to 100-180°C. We place the pore data into a detailed mineralogical, petrographical, and textural context to show that the nature and evolution of porosity and pore systems can be described in terms of associations with clay-rich, microfossil-rich, and organic matter-rich domains, common to many mudstones. Pore size distributions are described by power laws, and pore systems are well connected across the full nanometermicrometer spectrum of pore sizes. However, connected networks occur primarily through pores <10 nm radius, with typically 20-40% of total porosity associated with pores with radii <~3 nm, within both organic matter and the clay matrix. Clay-rich, microfossil-rich, and organic matter-rich domains have distinct pore size distributions which evolve in very different ways with increasing thermal maturity. We suggest that the flow of aqueous and nonaqueous fluids depends not only on the overall connectivity of pores but also the larger-scale connectivity and wetting state of clay-rich, microfossil-rich, and organic matter-rich domains.Plain Language Summary Mudstones are Cinderella sediments: important but neglected. The most abundant sediment type, they act as unconventional oil and gas reservoirs, as top seals to conventional hydrocarbon reservoirs, and as critical barriers to the leakage of CO 2 and radionuclides from underground storage sites. Risking and predicting flow and leakage through these rocks requires a quantitative description of pore systems and their connectivity. This is challenging since even the biggest pores in shales are smaller than a micron, with many pores only a few nanometers in size. Our work uses a combination of techniques to characterize and quantify the nanoporous nature of shales. Pores are generally smaller than 100 nm but are well connected, but mainly through throats less than 20 nm. We have also placed the pore system data into a geological framework in order to be more predictive about the pore systems of shales generally. By quantifying the nature of pores in the various mineral and organic building blocks of shales we can consider the larger scale flow properties of shales and thus their potential either to transmit fluid (useful for a shale gas reservoir) or to retain fluid (useful for a CO 2 or nuclear waste storage site).Quantitative descriptions of pore systems underpin our understanding of the storage and flow of both aqueous and nonaqueous fluids in...

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“…e current general opinion is that inorganic minerals are water wettability under the original reservoir conditions, while the organic matter is oil wettability [20][21][22][23]. e type of kerogen will affect the oil wettability of organic matter.…”

Section: Introductionmentioning

confidence: 99%

Study on the Wettability and Spontaneous Imbibition Characteristics of Lacustrine Shale

et al. 2022

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Wettability plays a significant role in the exploration and development of shale oil. The wettability affects the oil enrichment and restricts the selection of fracturing fluids. Shale is composed of complex minerals and organic matter. The pores composed of inorganic minerals have water wettability, while the pores composed of organic matter show the characteristics of oil wetting. The contact angle experiment and the spontaneous imbibition experiment are the most commonly used methods for characterizing wettability. The Qingshankou Formation in the Songliao Basin has thick source rocks, which is a favorable interval for shale oil exploration and development. Strengthening the wettability research in this area is of great significance for the exploration of shale oil. The wettability of different lithofacies shale in the northern Songliao Basin is seldom characterized, and there is a lack of comparative studies on contact angle and imbibition characteristics. In view of this situation, the shale of the Qingshankou Formation in the northern Songliao Basin has been classified. This article used the method of spontaneous imbibition combined with nuclear magnetic resonance to characterize the wettability of shale and analyze the influencing factors of the wettability of different shale lithofacies. Six samples with different lithological characteristics were used for this experiment. The study found that the imbibition results of samples with different lithofacies are different. The imbibition of sandy interlayer is less affected by the direction, while the imbibition of shale is more affected by the direction. The water imbibition volume of the sample is related to the content of clay minerals. The relationship of water imbibition volume in different lithofacies samples is as follows: low organic matter laminated siliceous shale > high organic matter massive clay shale > sandy interlayer > high organic matter laminated siliceous shale > high organic matter massive siliceous shale. Excessive content of clay minerals will cause shale to absorb water and expand and block pores, which is not conducive to further water imbibition by shale. The volume of oil imbibed is related to the organic carbon content. The relationship of oil imbibition volume in different lithofacies samples is as follows: high organic matter massive clay shale > high organic matter laminated siliceous shale > sandy interlayer > low organic matter laminated siliceous shale > high organic matter massive siliceous shale. The higher the total organic carbon content, the more developed the lipophilic pore network, and the more the volume of oil imbibed by the sample.

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The wettability of shale by NMR measurements and its controlling factors

Cited by 54 publications

References 16 publications

Shale Wettability: Data Sets, Challenges, and Outlook

Shale Wettability: Data Sets, Challenges, and Outlook

Influence of Clay, Calcareous Microfossils, and Organic Matter on the Nature and Diagenetic Evolution of Pore Systems in Mudstones

Study on the Wettability and Spontaneous Imbibition Characteristics of Lacustrine Shale

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