Evaluation of Fluid Saturation in Shale Using 2D Nuclear Magnetic Resonance

Gu, Mingxuan; Xie, Ranhong; Guo, Jiangfeng; Jin, Guowen

doi:10.1021/acs.energyfuels.2c03383

“…This approach integrates NMR, X-ray diffraction (XRD), and scanning electron microscopy (SEM) techniques, enabling the identification and quantitative assessment of different fluid saturations within the samples. Gu et al [13] developed a novel method for fluid saturation assessment, integrating morphological analysis, non-negative matrix decomposition, and fully constrained least squares, and applied two-dimensional NMR for evaluating fluid saturation in shale. Li et al [14] conducted a comprehensive assessment of water and oil content, their distribution, and evaporation loss patterns in preserved shale using two-dimensional NMR T1-T2 mapping techniques.…”

Section: Introductionmentioning

confidence: 99%

A New Method for Shale Oil Injecting-Stewing-Producing Physical Modeling Experiments Based on Nuclear Magnetic Resonance

Li,

Sun,

Liu

et al. 2024

Energies

0

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Enhancing oil recovery in shale is a critical technology for improving shale oil extraction efficiency. It is essential to develop a comprehensive set of physical simulation methods that are coherent and aligned with practical field operations. This paper establishes an integrated experimental approach, encompassing the entire Injecting-Stewing-Producing cycle, to simulate the actual Huff-n-Puff process accurately. Initially, the fracturing and flowback states are simulated by injecting an imbibition fluid, followed by a 48 h well-soaking process using CO2. The extraction is then carried out under various pressures. The microtransportation of crude oil across different pore sizes and the extent of extraction during shale oil Huff-n-Puff are investigated using Nuclear Magnetic Resonance technology. The results suggest that there was an initial increase in crude oil within pores smaller than 20 nm at the beginning of the Huff-n-Puff process. In Contrast, crude oil in pores larger than 200 nm was preferentially extracted, with oil in smaller pores (<200 nm) migrating to larger pores before extraction. After the initial Huff-n-Puff cycle, the extraction efficiency of the shale oil core reaches 29.55%, constituting 63.3% of the total extraction achieved over three Huff-n-Puff cycles. This study also identifies a critical pressure drop to 60% of the initial pressure as the optimal point for injection in subsequent Huff-n-Puff cycles. These experimental insights provide valuable guidance for the practical implementation of enhanced oil recovery techniques in shale formations.

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“…In the petroleum industry, nuclear magnetic resonance (NMR) relaxation time distributions serve as vital measurements for determining porosity, pore size distribution, and rock characteristics, such as permeability, wettability, capillary pressure, and residual oil saturation. − The transverse relaxation T 2 distribution, generated by the Carr–Purcell–Meiboom–Gill (CPMG) pulse sequence, forms the cornerstone of both laboratory and downhole NMR-logging measurements. − However, in most cases, conventional T 2 distribution measurements assume isotropic core samples and perform bulk measurements, focusing on capturing whole-sample signal components despite the frequent macroscopic heterogeneity observed in reservoir rocks. As exploration and development shift toward highly heterogeneous reservoirs like shale and carbonate formations, it is urgent to explore spatially resolved T 2 measurements to investigate the spatially resolved petrophysical properties of unconventional rocks with frequently finer bedding plane structures. , …”

Section: Introductionmentioning

confidence: 99%

Application Limits and Influencing Factors in Characterization of Rock Cores Using the Phase-Encoded T₂-y Method in Low-Field NMR

Liang,

Jia,

Xiao

et al. 2024

Energy Fuels

1

0

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The low-field nuclear magnetic resonance (LF NMR) technique proves valuable in determining porosity, permeability, pore size, and wettability through T 2 measurements in rocks. Recently, there has been growing interest in low-field nuclear magnetic resonance imaging (LF MRI) technology, which can provide sliced T 2 distributions and position profiles for the oil industry. However, there is a lack of detailed observation and discussion on the relevant application limitations and influencing factors. This work addresses this gap by presenting a comprehensive experiment and numerical investigation aimed at exploring T 2 -y maps for high-porosity sandstone and low-porosity dolomite cores using a phase-encoded T 2 imaging method. First, experiments were conducted to obtain sliced porosity and permeability for estimating rock heterogeneity along the core height. It was noted that T 2 components shorter than 0.3 ms were overlooked, leading to underestimated NMR porosity when comparing MRI-projected T 2 distributions with bulk T 2 distributions. Then, typical micropore modeling and magnetization evolution were employed to simulate and discuss factors, affecting the accuracy of the MRI T 2 spectra and image profiles. These factors include the off-resonance frequency caused by the external static magnetic field or internal field, the imaging-encoded time, the excitation pulse angle, the refocusing pulse angle, and gradient properties. The results showed that field inhomogeneity significantly influenced MRI-T 2 relaxation, particularly at high off-resonance frequencies. It was found that minimizing the image-encoded time is ideal for measuring short relaxation components. Additionally, the excitation pulse angle greatly impacted the amplitude of the T 2 distributions, whereas the refocusing pulse angle affected both the amplitude and the peak values of the T 2 spectra, especially in higher magnetic field inhomogeneity. Increasing gradient strength and duration were beneficial for imaging profiles but detrimental to the T 2 distribution and porosity. The investigation offers both practical guidance and theoretical insight for undertaking T 2 -y measurements in rocks, facilitating the optimization of the pulse sequence and the acquisition conditions, as well as the manipulation of the magnetization data.

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An NMR-based model for determining irreducible water saturation in carbonate gas reservoirs

Heidary

2024

J Petrol Explor Prod Technol

2

0

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Unambiguously determining irreducible water saturation $$\left({S}_{\rm{wirr}}\right)$$ S wirr poses a formidable challenge, given the availability of multiple independent methods. Traditional approaches often depend on semi-experimental relationships derived from simplified assumptions. These methods, originally designed for oil sandstone reservoirs, result in varying $${S}_{{\text{wirr}}}$$ S wirr values when employed in carbonate gas reservoirs. Nuclear magnetic resonance (NMR) is the most advanced technique for determining $${S}_{{\text{wirr}}}$$ S wirr . While highly accurate, the NMR-based method necessitates the laboratory measurement of the transverse relaxation time $$\left({T}_{2}\right)$$ T 2 cutoff. Laboratory-based $${T}_{2}$$ T 2 cutoff determination is resource-intensive and time-consuming. This research aims to develop a robust model for determining $${S}_{{\text{wirr}}}$$ S wirr in carbonate gas reservoirs by utilizing NMR well logging measurements and special core analysis (SCAL) tests. Various $${T}_{2}$$ T 2 cutoff values were initially employed to compute bound water saturation $$\left({S}_{{\text{bw}}}\right)$$ S bw at different depths to achieve this. Subsequently, the data points $$\left({T}_{2}, {S}_{{\text{bw}}}\right)$$ T 2 , S bw were graphed on a scatter plot to unveil the relationship between $${S}_{{\text{bw}}}$$ S bw and $${T}_{2}$$ T 2 . The scatter plot illustrates an exponential decrease in $${S}_{bw}$$ S bw with increasing $${T}_{2}$$ T 2 , forming the basis for the $${S}_{{\text{wirr}}}$$ S wirr model derived from this relationship. Finally, the parameters of the $${S}_{{\text{wirr}}}$$ S wirr model were fine-tuned using SCAL tests. Notably, this $${S}_{{\text{wirr}}}$$ S wirr model not only accurately yields $${S}_{{\text{wirr}}}$$ S wirr at each depth but also offers a dependable determination of the optimal $${T}_{2}$$ T 2 cutoff for the reservoir interval.

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Evaluation of Fluid Saturation in Shale Using 2D Nuclear Magnetic Resonance

Cited by 6 publications

References 25 publications

A New Method for Shale Oil Injecting-Stewing-Producing Physical Modeling Experiments Based on Nuclear Magnetic Resonance

A New Method for Shale Oil Injecting-Stewing-Producing Physical Modeling Experiments Based on Nuclear Magnetic Resonance

Application Limits and Influencing Factors in Characterization of Rock Cores Using the Phase-Encoded T₂-y Method in Low-Field NMR

An NMR-based model for determining irreducible water saturation in carbonate gas reservoirs

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Evaluation of Fluid Saturation in Shale Using 2D Nuclear Magnetic Resonance

Cited by 6 publications

References 25 publications

A New Method for Shale Oil Injecting-Stewing-Producing Physical Modeling Experiments Based on Nuclear Magnetic Resonance

A New Method for Shale Oil Injecting-Stewing-Producing Physical Modeling Experiments Based on Nuclear Magnetic Resonance

Application Limits and Influencing Factors in Characterization of Rock Cores Using the Phase-Encoded T2-y Method in Low-Field NMR

An NMR-based model for determining irreducible water saturation in carbonate gas reservoirs

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Product

Resources

About

Application Limits and Influencing Factors in Characterization of Rock Cores Using the Phase-Encoded T₂-y Method in Low-Field NMR