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•Introducing, for the first time, a magnetic resonance imaging method for shales.•The imaging method can provide water and oil images on a macroscopic scale.•Water and oil saturations ...depend on the macroscopic scale heterogeneity of bedding planes.•T1-T2∗ technique permits differentiating shale fracture and matrix pore water.•Monitoring shale water imbibition using a combination of MR Imaging and T1-T2∗ techniques.
Fluid storage and transport in shale and clay formations is important in many areas of application, including hydrocarbon recovery from, and waste fluid storing in, these reservoirs. The multiscale heterogeneous nature of shales is largely responsible for these rocks being considered unconventional and complicated. Researchers often rely on imaging methods to provide spatial information to characterize their heterogeneity.
SEM and nano-CT are powerful methods that have been used to give images of shale nanopores with fields of view (FOV) of 100 μm. However, this limited FOV has raised questions about the validity of simulations based on these methods to scale up and represent macroscopic shale properties. Here, we have used, for the first time, SPRITE Magnetic Resonance Imaging (MRI) methods to give core plug size shale images. The imaging method resolves water and oil signals to give separate images of each in shales.
“As received” shale samples were used to acquire 1D and 3D oil and water images to characterize natural fluid distribution. Water uptake experiments were conducted to probe fluid displacement in shales. Measurements included gravimetric, Magnetic Resonance (MR) T1-T2∗ relaxation correlation, and SPRITE imaging methods. Water and oil images showed that sample scale heterogeneities are imposed by the shale beddings. Water uptake experiments (1) showed the capability of the T1-T2∗ method to identify MR signals from shale fracture water and matrix pore water, and (2) illustrated wettability control of spatial water distribution in shales during spontaneous imbibition.
The majority of low field Magnetic Resonance (MR) analyses rely on T
lifetime measurements. Modification of the T
measurement to include a T
dimension has made the T
-T
measurement a very powerful ...analytical technique. The T
-T
measurement is uniquely well suited to characterization of different spin populations in porous materials, such as fluid bearing reservoir rocks, and in soft biopolymer materials, for example foods. However, the T
-T
measurement is challenging or impossible if the T
relaxation lifetime, or a component lifetime, is short-lived and the signal unobservable in an echo measurement. This occurs in many important classes of materials. A short lifetime T
will not however, in general, preclude observation of a free induction decay with signal decay governed by T
*. As outlined in this paper a T
-T
* measurement is a useful analog to the T
-T
experiment. T
-T
* measurement enables one to differentiate species as a function of T
* in one dimension and T
in the other dimension. Monitoring changes of the T
-T
* coordinate, and associated signal intensity changes, has the potential to reveal structural changes in materials evolving in time. These methods may also be employed to discriminate and identify solid-like species present in static samples. The T
-T
* measurement is very general in application, but in this paper we focus on cement-based mortars to develop and illustrate the essential ideas. T
-T
* results show a multi-modal behaviour of the MR signal lifetimes, T
and T
*, in mortar samples under study, indicating at least two different water populations. The short T
* lifetime was assigned to interlayer water (water between C-S-H layers) where the associated T
is also short lived. The longer T
* lifetime was assigned to water in the pore space, where T
is also longer lived. In addition to mortar samples we also show application of the method to a crystalline organic species, o-phenylenediamine, which features Sinc Gaussian and exponential decays of transverse magnetization.
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•Systematic study of core plugs with 3D Fast Spin Echo, and 3D SPRITE MRI methods.•A variable field superconducting magnet was used at: 0.79 T, 1.5 T, and 3 T.•FSE quantitative ...imaging employed to estimate local porosity in core plugs.•3D SPRITE measurements of fluid saturation is recommended for core analysis.•3 T is too high a static field in general for rock core MRI studies.
Fast Spin Echo MRI is now widely employed in biomedicine for proton density and T2 contrast imaging. Fast Spin Echo methods provide rapid data acquisition by employing multiple echoes to determine multiple k-space lines with single excitations. Due to the multi-exponential behavior of T2 in typical porous media, and the strong dependence of T2 on the details of the experiment, acquiring a proton density image with Fast Spin Echo methods requires favorable sample and acquisition parameters. In recent years, we have shown the value of pure phase encode Free Induction Decay based methods such as SPRITE. However, in a reservoir rock, a typical T2* is hundreds of µs, whereas a typical T2 is hundreds of ms. Hence, there is merit in considering spin echo-based MRI measurements such as the Fast Spin Echo for rock core plug studies.
A variable field superconducting magnet was employed in this study. This is a new class of magnet for MR/MRI. These magnets have the flexibility of operation in the field range of 0.01 Tesla to 3 Tesla. This is advantageous when working with rock core plugs, as it allows one to maximize sample magnetization, by increasing the static field while controlling magnetic susceptibility mismatch effects, and thereby T2 and T2*, through reducing the static field. The magnetic fields employed in the study were 0.79, 1.5, and 3 Tesla.
Measurements were undertaken on five brine-saturated reservoir rock core plugs (Bentheimer, Berea, Buff Berea, Nugget, and Wallace). The results show that Fast Spin Echo measurements are more sensitive than SPRITE methods in amenable samples and usually feature higher resolution. Quantification of saturation with Fast Spin Echo methods requires correction for T2 attenuation. The results also show that 3 Tesla is too high a static field in general for rock core MRI studies with either method. While the current study is focused on five representative reservoir rock cores, the conclusions which result are general for MRI of fluids in porous media.
Emulsion stability is important in many environmental and industrial applications. Unstable emulsions tend to have a layered structure which will evolve in space and time. Magnetic Resonance (MR) is ...a nondestructive method that can be used to study emulsion instability based on relaxation times (T1, T2), and/or diffusion (D). The bulk transverse relaxation lifetime (T2) is the most useful parameter for analysis. Since breaking of emulsions creates different layers and phases, spatially resolved T2 data is more valuable than bulk whole sample data. Previous literature studies were principally based on bulk T1, T2 or self-diffusion measurements without spatial resolution. In this study, for the first time, spatially resolved T2 distributions were used to examine oil and water behavior during emulsion breaking.
Diluted bitumen was used as the oil phase in a synthetic emulsion. Measurements undertaken included spatially resolved T2 distribution measurements and T1-T2 relaxation correlation measurements. The results reveal changes in the relaxation times of oil and water caused by changes in the dynamics of the water and oil during emulsion breaking. In each layer of the sample, comparing peak T2 values with bulk T2 values of different components gives an insight into phase environments. Water and oil content in each layer was resolved by using peak areas of the T2 distribution. The results of T2 distribution imaging were consistent with optical microscopy images, which showed W/O emulsions in the oil dominant region and complex W/O/W emulsions in the water dominant region of the sample. With the above information one can obtain full spatial and temporal information on evolving phases as well as kinetics of phase dynamics in emulsion breaking.
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•MR T2 mapping helps identify different layers of an emulsion sample and observe their evolution.•Optical microscopy images confirmed MR T2 mapping results.•The oil- and water-dominant regions were characterized by W/O and W/O/W emulsions respectively.•Spatial and temporal information on dispersed and free phases in the emulsion breaking is obtained.
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•Magnetic resonance methods were performed to characterize kerogen in shales.•Relaxation correlation method quantifies water, oil, and kerogen hydrogen content.•T1-T2* method coupled ...with pyrolysis showed kerogen dominates short T2* signal.•Free induction decay is adequate to resolve and quantify kerogen signal.•An elemental balance estimated the kerogen pyrolysis path on Van Krevelen diagram.
Kerogen assessment is essential to evaluation of shale reservoir quality. Routine analysis techniques are sample destructive and time-consuming. 1H magnetic resonance (MR) methods offer a fast, robust, and non-destructive alternative. However, kerogen MR signal detection and quantification is challenging due to its short signal lifetime and requires new MR methods. In this work, the T1-T2* relaxation correlation method was investigated for assessment of kerogen in shales. Step pyrolysis experiments were conducted coupled with MR T1-T2* relaxation correlation measurements and thermogravimetric analysis (TGA). The results show that the short relaxation lifetime signal observed in the shale samples was dominated by the kerogen species. The shale signal was resolved in the T1-T2* relaxation correlation measurement that was calibrated to report kerogen, oil, and water 1H content of the shale samples. Kerogen 1H content was then used to evaluate the hydrocarbon generation potential of kerogen. An elemental balance analysis was conducted to estimate the kerogen chemical evolution in the Van Krevelen diagram. The results proved that a simple FID measurement was adequate to resolve and quantify the kerogen signal component in shales.
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•T1-T2* measurement permits speciation of different spin populations when a T1-T2 measurement is impossible.•Tracking the T1-T2* coordinate, and associated intensity may reveal ...structural changes.•The T1-T2* measurement permits a simple assignment of T1 to different T2* populations.•The T1-T2* measurement will permit discrimination solid-like species in mixtures.
The majority of low field Magnetic Resonance (MR) analyses rely on T2 lifetime measurements. Modification of the T2 measurement to include a T1 dimension has made the T1-T2 measurement a very powerful analytical technique. The T1-T2 measurement is uniquely well suited to characterization of different spin populations in porous materials, such as fluid bearing reservoir rocks, and in soft biopolymer materials, for example foods. However, the T1-T2 measurement is challenging or impossible if the T2 relaxation lifetime, or a component lifetime, is short-lived and the signal unobservable in an echo measurement. This occurs in many important classes of materials. A short lifetime T2 will not however, in general, preclude observation of a free induction decay with signal decay governed by T2*.
As outlined in this paper a T1-T2* measurement is a useful analog to the T1-T2 experiment. T1-T2* measurement enables one to differentiate species as a function of T2* in one dimension and T1 in the other dimension. Monitoring changes of the T1-T2* coordinate, and associated signal intensity changes, has the potential to reveal structural changes in materials evolving in time. These methods may also be employed to discriminate and identify solid-like species present in static samples.
The T1-T2* measurement is very general in application, but in this paper we focus on cement-based mortars to develop and illustrate the essential ideas. T1-T2* results show a multi-modal behaviour of the MR signal lifetimes, T1 and T2*, in mortar samples under study, indicating at least two different water populations. The short T2* lifetime was assigned to interlayer water (water between C–S–H layers) where the associated T1 is also short lived. The longer T2* lifetime was assigned to water in the pore space, where T1 is also longer lived. In addition to mortar samples we also show application of the method to a crystalline organic species, o-phenylenediamine, which features Sinc Gaussian and exponential decays of transverse magnetization.
•New insight in magnetic resonance relaxation mechanisms of 1H-bearing compounds in shales.•A novel 2D magnetic resonance T1-T2∗ technique is introduced for shale fluid typing.•T1-T2∗ capability in ...quantifying water in adsorption/desorption process is studied.•A procedure is provided to quantify shale fluid content based on the T1-T2∗ technique.•T1-T2∗ technique provides quantitative 1H content of kerogen allowing geochemical studies.
Quantification of fluid and organic matter content of shale samples are principal goals of petrophysical and geochemical evaluation of shales that are essential to determine reservoir quality. While volumetric methods to characterize shales are cumbersome and destructive, 1H magnetic resonance (MR) methods are robust, fast, and non-destructive. However, short-lived MR signal lifetimes of shale samples challenge existing MR methods and motivate the development of new MR methods.
Two-dimensional (2D) MR T1-T2 relaxation correlation is a powerful method to differentiate hydrogen-bearing species in porous materials. However, the experimental echo time limitation of the T1-T2 method precludes acquisition of important short lifetime signal components. In addition, due to overlap of signal components in T1-T2 correlations, quantification accuracy is impaired in shales. Here, we introduce the 2D MR T1-T2∗ relaxation correlation measurement for quantitative determination of shale 1H components.
Liquid-rich shale samples from the Eagle Ford Formation were used in adsorption/desorption and evaporation experiments. 2D MR T1-T2 and T1-T2∗ correlations coupled with gravimetric measurements were performed to identify water, oil/bitumen, and kerogen peaks in the relaxation correlation maps. Peaks associated with shale components showed significant contrast in T1-T2∗ correlations. This allowed quantitative measurement of water and oil content using the signal intensity of each peak.
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