Determination of movable fluid percentage and movable fluid porosity in ultra-low permeability sandstone using nuclear magnetic resonance (NMR) technique

Gao, Hui; Li, Huazhou

doi:10.1016/j.petrol.2015.06.017

Cited by 188 publications

(117 citation statements)

References 15 publications

(21 reference statements)

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“…Additionally, the parameters FFI and T 2gm are commonly used for the estimation of permeability. The T 2cutoff , which separates the capillary and clay‐bound water (BVI) residing in the small pores (short T 2 components) from the mobile water (FFI) residing in the large pores (long T 2 components) (Figure ), could be determined from the method given by Gao and Li, based on the NMR measurements at saturated and irreducible conditions . Additionally, the volumes of irreducible (BVI) and mobile (FFI) fluids could be estimated based on the T 2cutoff value .…”

Section: Resultsmentioning

confidence: 99%

Effect of pore structure on oil‐bearing property in the third member of Paleogene Funing Formation in Subei Basin, East China

Liu

Xie

Shu

et al. 2020

Energy Science & Engineering

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Mercury injection capillary pressure (MICP) tests, nuclear magnetic resonance (NMR), (fluorescence) thin section, X-ray diffraction (XRD), and scanning electron microscope (SEM) analyses were used to describe the size and distribution of entire pore-throat structures in the sandstones of the E 1 f 3 (the third member of Paleogene Funing Formation) in the Subei Basin. The lithologies of E 1 f 3 in the Subei Basin are mainly dark-gray, very fine-grained sandstones and siltstones, interbedded with dark mudstones. The pore systems predominantly feature secondary intergranular and intragranular dissolution pores, micropores coexisting with minor amounts of intergranular pores, and microfractures. The high threshold pressure and bulk volume of irreducible fluids values and the significant variation in the NMR and MICP parameters indicate that the E 1 f 3 reservoirs are characterized by complex and heterogeneous microscopic pore structures. Microscopic pore-throat parameters are linked with macroscopic properties through the reservoir quality index (RQI). The NMR T 2 (transverse time relaxation) spectrum is unimodal or bimodal but with weak right peaks, indicating the rarity of large intergranular pores. However, large-scale pore throats, though only account for a minor part of the total pore volume, significantly contribute to the total permeability. The abundance of small-scale pore-throat systems (short T 2 components) results in high irreducible water content. Therefore, the oil saturation in E 1 f 3 sandstones is low, and the pore structure, especially the number of micropores, determines the oil-bearing property. Oil primarily occurs in the intragranular dissolution pores with minor amounts occurring in the large intergranular pores. Most of the micropores are bound by capillary water. The sandstones with chlorite clay minerals tend to be oil-wet and have high oil-bearing potential, while the abundance of detrital clay or illite contributes to a low oil-bearing grade. The combination of core and microscopic observations and the MICP and NMR analyses have allowed the determination of the pore structure characteristics and their coupling effects on oil-bearing property. |

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Section: Resultsmentioning

confidence: 99%

Effect of pore structure on oil‐bearing property in the third member of Paleogene Funing Formation in Subei Basin, East China

Liu

Xie

Shu

et al. 2020

Energy Science & Engineering

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“…Porosity is an extensively used index to evaluate the pore volume of inner pores/fractures in oil shale. Previous studies noted that the signal intensity of the hydrogen-containing fluid (n-C 12 in this study) in samples is able to investigate the NMR porosity [40][41][42]. Accordingly, a series of NMR measurements were, respectively, conducted on five standard n-C 12 samples (0.2, 0.4, 0.6, 0.8, and 1.0 mL).…”

Section: Effective Porositymentioning

confidence: 99%

Pore Structure Petrophysical Characterization of the Upper Cretaceous Oil Shale from the Songliao Basin (NE China) Using Low-Field NMR

Liu

Zhang

Bai

et al. 2020

Journal of Spectroscopy

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Low-field NMR theory was employed to study the pore structure of the upper cretaceous oil shale, on the basis of fourteen core samples collected from Qingshankou (UCQ) and Nenjiang (UCN) formations in the Songliao basin. Results indicated that the T 2 spectra from NMR measurements for collected samples contain a dominant peak at T 2 � 1∼10 ms and are able to be categorized as three types-unimodal, bimodal, and trimodal distributions. e various morphologies of T 2 spectra indicate the different pore type and variable connection relationship among pores in shale. By contrast, UCN shale has more single pore type and adsorption pores than UCQ shale. Besides, NMR-based measurements provide reliable characterization on shale porosity, which is verified by the gravimetric approach. Porosities in both UCN and UCQ shales have a wide range (2.3%∼12.5%) and suggest the strong heterogeneity, which partly makes the challenge in selection of the favorable area for shale oil exploration in the Songliao basin. In addition, the pore size of the collected sample has two distribution types, namely, peaked at ∼10 nm and peaked at ∼100 nm. Similarly, two distribution patterns emerge to the specific surface area of the study shale-peaked at ∼2 nm − 1 and peaked at ∼20 nm − 1 . Here, more investigations are needed to clarify this polarization phenomenon. Basically, this study not only exhibits a preliminary understanding on the pore structure of the upper cretaceous oil shale, but also shows the reliability and pertinency of the low-field NMR technique in the petrophysical characterization of the shale oil reservoir. It is expected that this work is helpful to guide the investigation on the pore structure of oil shale from the Songliao basin in theory.

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“…The T 2 cutoff was the key parameter for calculating movable fluid saturation in the NMR experiment, the left side of the T 2 cutoff represents bound fluid, and the right side represents movable fluid [42]. The T 2 cutoff varied according to differences in the specific surface area of each sample [43]. Figure 10 shows the method of calculating the T 2 cutoff value.…”

Section: T 2 Cutoffmentioning

confidence: 99%

Quantitative Characterization of Pore Connectivity and Movable Fluid Distribution of Tight Sandstones: A Case Study of the Upper Triassic Chang 7 Member, Yanchang Formation in Ordos Basin, China

et al. 2020

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The pore connectivity and distribution of moveable fluids, which determines fluid movability and recoverable reserves, are critical for enhancing oil/gas recovery in tight sandstone reservoirs. In this paper, multiple techniques including high-pressure mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), and microcomputer tomography scanning (micro-CT) were used for the quantitative characterization of pore structure, pore connectivity, and movable fluid distribution. Firstly, sample porosity and permeability were obtained. Pore morphology and the 3D distribution of the pore structures were analyzed using SEM and micro-CT, respectively. The pore-size distribution (PSD) from NMR was generally broader than that from MIP because this technique simply characterized the connected pore volume, whereas NMR showed the total pore volume. Therefore, an attempt was made to calculate pore connectivity percentages of pores with different radii (<50 nm, 50 nm–0.1 μm, and 0.1 μm–1 μm) using the difference between the PSD obtained from MIP and NMR. It was found that small pores (r<0.05 μm) contributed 5.02%–18.00% to connectivity, which is less than large pores (r>0.05 μm) with contribution of 36.60%–92.00%, although small pores had greater pore volumes. In addition, a new parameter, effective movable fluid saturation, was proposed based on the initial movable fluid saturation from NMR and the pore connectivity percentage from MIP and NMR. The results demonstrated that the initial movable fluid saturation decreased by 14.16% on average when disconnected pores were excluded. It was concluded that the effective movable fluid saturation has a higher accuracy in evaluating the recovery of tight sandstone reservoirs.

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Determination of movable fluid percentage and movable fluid porosity in ultra-low permeability sandstone using nuclear magnetic resonance (NMR) technique

Cited by 188 publications

References 15 publications

Effect of pore structure on oil‐bearing property in the third member of Paleogene Funing Formation in Subei Basin, East China

Effect of pore structure on oil‐bearing property in the third member of Paleogene Funing Formation in Subei Basin, East China

Pore Structure Petrophysical Characterization of the Upper Cretaceous Oil Shale from the Songliao Basin (NE China) Using Low-Field NMR

Quantitative Characterization of Pore Connectivity and Movable Fluid Distribution of Tight Sandstones: A Case Study of the Upper Triassic Chang 7 Member, Yanchang Formation in Ordos Basin, China

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