Updated methodology for nuclear magnetic resonance characterization of shales

Washburn, Kathryn E.; Birdwell, Justin E.

doi:10.1016/j.jmr.2013.04.014

Cited by 136 publications

(71 citation statements)

References 34 publications

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“…For example, the very short probe recovery times at ν 0 ∼ 10 MHz are appropriate for studies of shale, 16,18,54 and the compromise between maximum SNR and minimum internal gradient strength makes such systems ideal for monitoring flow in porous materials. 14,25 Overall, an intermediate field imaging platform greatly increases the suite of NMR measurements available in a core analysis laboratory and offers a versatile platform for studying transport through porous media in general.…”

Section: Discussionmentioning

confidence: 99%

“…14 The slow recovery of the rf receiver chain after an excitation pulse prevents the detection of very short relaxation time components in shale samples. [15][16][17][18][19] Two-or three-dimensional (3D) imaging remains impractical at 2 MHz. Therefore, any low field core analysis may be complemented with measurements at a higher magnetic field strength to provide additional information on fluid distribution and transport in porous rocks.…”

Section: Introductionmentioning

confidence: 99%

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Contributed Review: Nuclear magnetic resonance core analysis at 0.3 T

Mitchell

Fordham

2014

Review of Scientific Instruments

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Nuclear magnetic resonance (NMR) provides a powerful toolbox for petrophysical characterization of reservoir core plugs and fluids in the laboratory. Previously, there has been considerable focus on low field magnet technology for well log calibration. Now there is renewed interest in the study of reservoir samples using stronger magnets to complement these standard NMR measurements. Here, the capabilities of an imaging magnet with a field strength of 0.3 T (corresponding to 12.9 MHz for proton) are reviewed in the context of reservoir core analysis. Quantitative estimates of porosity (saturation) and pore size distributions are obtained under favorable conditions (e.g., in carbonates), with the added advantage of multidimensional imaging, detection of lower gyromagnetic ratio nuclei, and short probe recovery times that make the system suitable for shale studies. Intermediate field instruments provide quantitative porosity maps of rock plugs that cannot be obtained using high field medical scanners due to the field-dependent susceptibility contrast in the porous medium. Example data are presented that highlight the potential applications of an intermediate field imaging instrument as a complement to low field instruments in core analysis and for materials science studies in general.

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Section: Discussionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Contributed Review: Nuclear magnetic resonance core analysis at 0.3 T

Mitchell

Fordham

2014

Review of Scientific Instruments

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“…NMR technology has been proved to be a good technique for studying the reservoir engineering properties of rocks (Martinez and Davis, 2000;Sigal and Odusina, 2011;Zhou et al, 2012;Washburn and Birdwell, 2013). In this study, the crosswise relaxation time t 2 distribution of three samples was obtained through NMR measurement.…”

Section: Knmentioning

confidence: 94%

Investigation of multi-scale gas transport behavior in organic-rich shale

Chen

Kang

et al. 2016

Journal of Natural Gas Science and Engineering

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“…Here, we find the relaxation times can be most efficiently described by five exponential decays. The shortest time we attribute to fluid (toluene or water) in nano pores or heavy hydrocarbons [7,8], the next three are toluene in micro (best fitted by two components suggesting two types of micropores) and macro pores (which may indicate fractures). The longest-T2 is for bulk toluene in distribution plugs and delivery lines.…”

Section: B Xmt Analysis Of Micro-structurementioning

confidence: 99%

Microstructural Investigation of S tress-Dependent Permeability in Tight-Oil Rocks

et al. 2018

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Recent studies on several core-plug scale samples from tight oil reservoirs have demonstrated that such rocks can exhibit a significant, irreversible permeability decline with increase in net confining stress. Because this effect closely follows the expected stress change during drawdown in the field, the origins of this phenomena as well as a method to predict the magnitude relative to different rock types is valuable information for reservoir management. To better understand this effect, we have undertaken a series of in situ studies that demonstrate how an external stress field translates to microscopic strain at the pore scale and couples to the fluid transport. These studies rely on the coordinated use of low-field Nuclear Magnetic Resonance (NMR) and X-ray Microtomography (XMT). Making use of labeled fluids to enhance contrast, we are able to directly resolve how local strains affect fluid transport throughout the core plug. In a similar manner, proton NMR resolves how stress couples to deformation of the various pore systems, affecting the fluid content and their dynamics. Together, these techniques indicate that internal, high-permeability pathways play an important role in the stress dependence. Matrix permeability is much less affected. These higher-permeability zones are not ubiquitous in tight-oil rocks. Characterizing these zones and relating them to mineralogy and rock fabric is an attractive pathway to greater predictability for stressdependent permeability for reservoir rock types. SCA2017-017 2/12 Changes in NCS can alter the permeability for unfractured rocks, matrix for tight/shales, and natural fractures. It can also affect hydraulic fractures, both propped and un-propped. Impairment of flow properties were found to be a function of the magnitude of pressure drawdown and the pressure history (hysteresis) [1-4]. Deterioration of the flow capability of the near-frac region alters the expected drainage area around fractures. Therefore, pressure dependent rock properties could provide key inputs for reservoir development business decisions in terms of well spacing, frac stage spacing, draw-down rates etc.

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Updated methodology for nuclear magnetic resonance characterization of shales

Cited by 136 publications

References 34 publications

Contributed Review: Nuclear magnetic resonance core analysis at 0.3 T

Contributed Review: Nuclear magnetic resonance core analysis at 0.3 T

Investigation of multi-scale gas transport behavior in organic-rich shale

Microstructural Investigation of S tress-Dependent Permeability in Tight-Oil Rocks

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