Nuclear Magnetic Resonance Porosity Research Articles

Microstructure characteristics and the damage evolution rule of sandstone under triaxial compression test using Nuclear Magnetic Resonance (NMR)

The complex microstructure of rock is very important for the stability of geotechnical engineering. However, the current research on the microstructure of rock mass can’t be monitored in real time. In this paper, rock microstructure under triaxial compression was studied using an online Nuclear Magnetic Resonance (NMR). The specimen was subjected to confining pressure of 10 MPa, then five levels of axial pressure were applied, and NMR is performed in real time after each axial compression is loaded.Research indicates: When the confining pressure is constant, the peak of T2 spectrum distribution curve decreases with the increase of axial pressure. The micropores grow in a parabolic fashion while the macropores grow in a quartic polynomial fashion. NMR porosity can be divided into three stages: initial growth stage, pore compaction stage and stable pore expansion stage. Macropore expansion plays a decisive role in porosity change in the initial growth stage and stable pore expansion stage, while micropore compaction plays a decisive role in pore compaction stage. NMR images can clearly and intuitively display the microstructure characteristics of specimens online.

Optimization of key parameters for porosity measurement of shale gas reservoirs

Porosity is a key parameter in shale gas reservoir evaluation and reserve calculation and its accurate test is the basis for calculating geological reserves of shale gas and determining development plans. In order to clarify the differences between different porosity test methods and their influences on the calculation results of shale gas reserves, we collected 65 shale samples of Lower Silurian Longmaxi Formation from six shale gas wells in the Zhaotong National Shale Gas Demonstration Area of the southern Sichuan Basin for comparative experiments using three porosity test method, including gas injection porosimetry (GIP) method, water immersion porosimetry (WIP) method and nuclear magnetic resonance (NMR) method. Then, these three methods were comparatively analyzed based on the test results. Finally, it was proposed to optimize the key parameters of these three shale porosity test methods. And the following research results were obtained. First, in terms of the GIP method, the particle size of shale sample shall be in the range of 20–60 mesh and the helium saturation equilibrium time shall be over 1800 s. Second, in terms of the WIP method, the sample shall be dried for at least 48 h under 110 °C and saturated for 24 h under the confining pressure of 15 MPa. Third, in terms of the NMR method, NMR porosity calculation shall not be conducted until the NMR signal of the dried sample is deducted, on the basis of echo time and waiting time optimization. Fourth, porosity average and median value obtained by these three shale porosity test methods follow the relationship of WIP porosity > NMR porosity > particle GIP porosity > plunger GIP porosity. Fifth, different shale porosity test methods have greater influences on the calculation results of shale gas geological reserves, whose difference can reach 20%. In conclusion, during the application of NMR method and WIP method, fluid is introduced for saturation, which may damage the shale pores. However, the particle GIP porosity can reflect the entire space of shale more comprehensively and is not influenced by the properties of the applied fluid. Therefore, it is suggested to adopt the particle GIP method to calculate shale gas geological reserves.

Rapid modeling of borehole measurements of nuclear magnetic resonance via spatial sensitivity functions

Borehole measurements of nuclear magnetic resonance (NMR) are routinely used to estimate in situ rock and fluid properties. Conventional NMR interpretation methods often neglect bed-boundary and layer-thickness effects in the calculation of fluid volumetric concentrations and NMR relaxation-diffusion correlations. Such effects introduce notable spatial averaging of intrinsic rock and fluid properties across thinly bedded formations or in the vicinity of boundaries between layers exhibiting large property contrasts. Forward modeling and inversion methods can mitigate the aforementioned effects and improve the accuracy of true layer properties in the presence of mud-filtrate invasion and borehole environmental effects across spatially complex formations. We have developed a fast and accurate algorithm to simulate borehole NMR measurements using the concept of spatial sensitivity functions (SSFs) that honor NMR physics and incorporate tool, borehole, and formation geometry. Tool sensitivity maps are derived from a 3D multiphysics forward model that couples NMR tool properties, magnetization evolution, and electromagnetic propagation. In addition, a multifluid relaxation model based on Brownstein-Tarr’s equation is introduced to estimate layer NMR porosity decays and relaxation-diffusion correlations from pore-size-dependent rock and fluid properties. The latter model is convolved with the SSFs to reproduce borehole NMR measurements. The results indicate that NMR spatial sensitivity is controlled by porosity, electrical conductivity, excitation pulse duration, and tool geometry. We benchmark and verify the SSF-derived forward approximation against 3D multiphysics simulations for a series of synthetic cases with variable bed thickness and petrophysical properties, and in the presence of mud-filtrate invasion in a vertical well. Results indicate that the approximation can be executed in a few seconds in a central processing unit, by a factor of 1000 times faster than rigorous multiphysics calculations, with maximum root-mean-square errors of 1%.

Influence of Rock Wettability on THF Hydrate Saturation and Distribution in Sandstones

Natural gas trapped in hydrate deposits is a potentially enormous source of energy which can in principle be extracted from the underground reservoir structures. These reserves can potentially also catastrophically release very large quantities of greenhouse gases to the atmosphere. One key parameter which is well known to strongly influence fluid distribution, saturation, and production is rock wettability. However, the effect of wettability on gas hydrate in sediments has not been investigated yet. We thus used nuclear magnetic resonance (NMR) spectrometry to measure relaxation times (T2 and T1) and the corresponding surface relaxivity of tetrahydrofuran hydrate during the formation and dissociation in water- and oil-wet Bentheimer sandstones. We also measured the NMR porosities and hydrate saturations at different temperatures during hydrate formation/dissociation for both water-wet and oil-wet sandstones. Significantly higher hydrate saturation was observed in the water-wet sandstone (when compared to the oil-wet sandstone) at all stages of hydrate formation and dissociation. Furthermore, the T2 spectra moved from the lower relaxation domain (before hydrate formation) to the fast relaxation domain (after hydrate formation) in both water-wet and oil-wet sandstones. However, the water-wet sandstone generally had a T2 relaxation range due to the higher water affinity to the water-wet rock and the associated faster demagnetization of the water molecules. These results demonstrate that low-field NMR can be used to quantify the rock wettability and observe hydrate behavior in geologic sediments. This fundamental information thus aids in the development of gas extraction from hydrate reservoirs and the assessment of potential greenhouse gas emissions from such reservoirs into the atmosphere.

Fractal characteristics of the microstructure of loaded coal based on NMR and μ-CT

ABSTRACT The change in the fracture microstructure of loaded coal affects the gas seepage characteristics of the coal. Using micron CT scanning (μ-CT) and nuclear magnetic resonance (NMR) experiments, the fractal characteristics of coal fracture structure under triaxial compression are studied from two aspects of theoretical and experimental fractal dimension for the first time. VG Studio MAX software was used to reconstruct the three-dimensional (3D) fracture structure of the coal samples, and the 3D fracture structure was modified by the porosity measured by NMR. Through the analysis of the reconstruction model and the T2 relaxation spectrum, the spatial distribution of internal cracks in coal was obtained. The fractal geometry theory, NMR experimental fractal dimension algorithm and 3D box counting method were used to calculate the theoretical and experimental fractal dimensions and then comprehensively analyze the fractal characteristics of cracks in loaded coal. The results show that an external load promotes the development of pores/cracks in coal. With increasing theoretical fractal dimension, CT porosity increases from 0.0630% to 0.101%, and NMR porosity increases from 0.0655% to 0.105%. The relationship between porosity and theoretical fractal dimension can be expressed by y = ax2+ bx+c (fractal dimension is an independent variable). With increasing porosity, the experimental fractal dimension of NMR decreases linearly from 2.975 to 2.951, and the experimental fractal dimension of μ-CT increases linearly from 2.191 to 2.324. The different changing trends of theoretical and experimental fractal dimensions verify the differences in their representational meanings.

Determination of In Situ Wettability Using Wavelet Analysis and Nuclear Magnetic Resonance Log Data

Knowledge of reservoir rock wettability is crucial for the understanding of fluid displacement mechanisms and for adopting feasible solutions to enhance oil recovery. Highly sensitive to the strength of fluid–rock interactions, nuclear magnetic resonance (NMR) measurements are a well-suited candidate for in situ wettability determination. Changes in correlation coefficients between NMR porosity $$\left( {\phi_{\rm NMR} } \right)$$ and transverse relaxation time $$\left( {T_{2} } \right)$$ can be used as a diagnostic parameter to determine in situ wettability. This paper aimed to take advantage of this promising feature to specify the downhole wettability of an oil well running through two carbonate reservoirs. In this regard, the correlation coefficient between $$\phi_{\rm NMR}$$ and $$T_{2}$$ was first computed at each depth. As a superior technique in analyzing nonstationary signals, the wavelet transform was then applied to the correlation coefficient log to remove shale content. Finally, the wavelet transform was re-applied to the modified correlation coefficient log to derive the detail coefficients. Scrutiny of the detail coefficients revealed a strong correlation with experimental wettability results. The results obtained from this investigation indicated that positive detail coefficients are associated with water-wet, and negative ones with oil-wet media.

Pore structure characteristics and their influencing factors: A case study from the middle jurassic mixed siliciclastic carbonate rocks, Turpan-Hami basin, Northwest China

The mixed siliciclastic-carbonate rocks of the second member of the Qiketai Formation (J2q2) in the Turpan-Hami Basin are lacustrine tight oil reservoir with vitrinite reflectance values (%, Ro) ranging from 0.64% to 0.81%. X-ray diffraction (XRD), thin sections, field emission scanning electron microscopy (FE-SEM) of argon-milled thin sections, low-temperature N2 adsorption (LNTA), and nuclear magnetic resonance (NMR) analyses were performed to investigate the pore structure characteristics and their influencing factors of the mixed siliciclastic-carbonate reservoirs. The results show that the tight reservoir has a medium-high total organic carbon (TOC) content, and the sedimentary textures include laminated, massive, and intraclasts-rich types. Nanometer scale interparticle pores and microfractures are dominant in the tight reservoirs. The small pores (2–100 nm) make a dominant contribution to the nanoscale storage space according to the comprehensive analysis of the T2 spectra of NMR. Reversed S-shaped isotherms obtained from N2 adsorption are type IV, and hysteresis loops indicate that the shape of pores include slit-or plate-like, ink-bottle-shaped and mixtures of the two. BET surface areas and BJH total pore volume vary from 1.707 m2/g to 8.556 m2/g and 1.13 cm3/100 g to 3.0 cm3/100 g, with an average of 4.31 m2/g and 1.848 cm3/100 g, respectively. The massive and intraclasts-rich rocks have higher NMR porosities, pore sizes and pore volumes than the laminated rocks. Based on the Frenkel-Halsey-Hill model of low-temperature N2 adsorption, the fractal dimensions D1 and D2 are 2.4305–2.7081 and 2.2667–2.6070, respectively. The correlations between the pore structure parameters and the mineralogical composition, TOC content, and fractal dimension reveal that dolomite makes greater contribution to the pore volume and movable fluid saturation than the siliciclastic gains and organic matter, resulting in higher fractal dimensions and more complicated pore structure. In addition, the clay minerals increase pore specific surface area and its complexity in the tight reservoirs. The samples with high silicate mineral and TOC contents tend to contain lower specific surface areas and pore volumes, resulting in lower fractal dimensions and more simplistic pore structure than clay rich samples. Therefore, the complex mineralogical composition, various sedimentary textures and organic matter content all play important roles in the development of pore network.

A workflow for multimineralogic carbonate rock physics modelling in a Bayesian framework: Brazilian pre‐salt reservoir case study

ABSTRACTWe develop a workflow to estimate elastic attributes ( and ) of Pre‐Salt carbonate reservoirs using the Xu and Payne rock physics model in a depth‐variant multimineralogic fashion and apply it to one calibration and four extrapolation wells in a field in the Brazilian Santos Basin. Some of the parameters were stochastically simulated in a Bayesian framework to handle the model non‐uniqueness. Nuclear magnetic resonance porosity and mineralogic logs and x‐ray powder diffraction data from the studied wells and literature reference values were used for elastic solid media and dual‐porosity network modelling, bringing geological reasoning to the proposed workflow. Using rock physics templates, we improved our understanding of the reservoir petroelastic trends and devised alternative model parameterizations. Since the model was parameterized in a multimineralogic fashion with depth‐variant mineralogic information (e.g. volumes of carbonate, quartz and clay) as input, we improved elastic attribute estimations within the reservoir, increasing the model predictive power, compared to the common practice of allowing only porosity to vary with depth and representing the matrix properties by a depth‐invariant homogeneous or mixed mineral. We also investigated the workflow robustness and non‐uniqueness by studying its dependence on the choice of calibration well.

Insight into pore-throat size distribution and the controls on oil saturation of tight sandstone reservoirs using nuclear magnetic resonance parameters: A case study of the Lower Cretaceous Quantou Formation in the southern Songliao Basin, China

Pore-throat structure characterization is crucial in tight-oil sandstone reservoir studies. To better understand pore-throat size distribution and the effects on reservoir oil saturation, petrographic, scanning electron microscopy, quantitative grain fluorescence (QGF), nuclear magnetic resonance (NMR), and pressure-controlled mercury injection investigations were performed on a suite of tight sandstones from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The tight sandstone samples showed similar compositional and textural maturity but different reservoir qualities at different depth intervals. Two oily indicators, QGF index and QGF on extract spectra intensity, varied significantly with respect to burial depth, suggesting the existence of strong oil heterogeneities in the K1q4 tight sandstones. Oil emplacement occurred mainly in the primary pores associated with the absence of pore-filling authigenic minerals. Pore-throat size distributions had wider ranges in the oil-rich layers than in the samples lacking oil emplacement. The NMR pore-throat radii ranged from 0.01 to 10 μm in oil lacking samples but ranged from 0.01 to 100 μm in oil-rich layers. Oil signals were mainly detected in the pore throats with radii ranging from approximately 0.1 to 1.0 μm in oil-rich layers. The NMR porosity can be divided into three parts based on transverse relaxation time (T2) spectrum: (1) immovable fluid, (2) porosity of effective movable fluid (PEMF), and (3) porosity of bound fluid. Bivariate plots of the ratios of various porosity types have significant effects in deciphering the oil saturation of tight sandstone reservoirs. The PEMF reflected well the reservoir QGF index, among others. Therefore, it can be considered as an effective NMR parameter to characterize pore size distribution and helpful in oil reservoir prediction. A good relationship exists between PEMF and geometric mean of the T2 distribution (T2gm), indicating that T2gm could also reflect reservoir oil saturation. The PEMF is mainly contributed by large pore throats, and the poorly sorted pore-throat distribution is better for effective movable fluids occurrence in tight sandstones. The approach employed in this study provides a more comprehensive and accurate pore-throat structure characterization in tight sandstone oil reservoirs, generating effective parameters and convenient ways to evaluate reservoir oil saturation. Importantly, it could be applicable for improving tight sandstone oil exploration and development efficiencies.

Petrophysical properties difference of organic-rich and organic-poor shale reservoir using low-field nuclear magnetic resonance experiment in the Sangzhi block, South China

The petrophysical properties of rocks have an important influence on shale quality. To characterize the difference of petrophysical properties between organic-rich and organic-poor shale reservoirs, we used the low-field nuclear magnetic resonance (NMR) technique and field emission scanning electron microscopy analysis after argon-ion polishing or natural section to measure porosity and permeability from six core samples from well SY6 in the Sangzhi block, Northwest Hunan province. Some information about pore types, pore structure, residual porosity, movable porosity, and permeability based on the T2 spectrums’ difference of organic-rich and organic-poor shale samples were discussed. The shale sample test results show that the main pores size is mesopore, which provide most of shale gas reservoir space. The continuous peaks demonstrated the pores’ connectivity better than the isolated peaks, and shale gas can migrate freely between these connected pores and fractures. The permeability of all samples calculated by the classic Coates model is extremely low, which is not conducive to the migration of shale gas. We evaluated the dominating factors of NMR porosity and permeability and found that the relationships between NMR porosity and permeability and total organic carbon content, quartz minerals, and clay minerals are not clear, which may be a comprehensive influence. The research results have important guiding significance for shale reservoir quality evaluation in this area.

The effect of magnetic susceptibility and magnetic field strength on porosity estimates determined from low-field nuclear magnetic resonance

The presence of materials with high magnetic susceptibility are known to have an impact on 1H nuclear magnetic resonance (NMR) measurements and in laboratory data this often results in poor estimates of porosity from NMR data. To quantify and understand the cause of the poor NMR porosity estimations, in this laboratory study, we examine the effect of magnetic susceptibility, NMR measurement parameters, and NMR instrument design on NMR measurements. Data were collected with two instruments, each with a different Larmor frequency (2 MHz and 485 kHz), on water-saturated unconsolidated sediments with magnetic susceptibility values ranging from 3.6 × 10−6 to 7020 × 10−6 SI. The results show that for materials with low magnetic susceptibility (<378 × 10−6 SI), the gravimetric porosity is accurately predicted from the NMR measurements. For the samples with high magnetic susceptibility (>987 × 10−6 SI) the gravimetric porosity is poorly predicted from the 2 MHz NMR measurements made at all echo times (from 0.2 to 3.0 ms). In contrast, the gravimetric porosity is more accurately predicted at an echo time of 0.2 ms for measurements made using the 485 kHz instrument, although at larger echo times (>1.0 ms), the porosity estimate becomes poor. The 485 kHz NMR instrument has non-zero internal magnetic field gradients, similar to those found in borehole instruments, in contrast to the 2 MHz NMR instrument, which has a homogeneous applied magnetic field. We conclude that differences is the magnetic field strength and higher magnetic field inhomogeneities in the 485 kHz NMR instrument contribute to a reduction of the impact of inhomogeneities in the magnetic field caused by materials with high magnetic susceptibility, allowing for improved porosity estimation. These results indicate that NMR measurements collected at short echo times in low, inhomogeneous static fields, e.g., borehole instruments, may provide accurate estimates of porosity in water saturated sediments, even in the presence of magnetic minerals.

Magnetic matrix effects on NMR relaxation times in sandstones: A case study in Solimões Basin

Pore distribution estimates based on Nuclear Magnetic Resonance (NMR) can be strongly affected by the presence of magnetic field gradients between the pore and the grain’s surface. Here we investigate the effect of the magnetic matrix on Uerê and Juruá reservoir sandstones (Solimões Basin, Brazil), where quartz, illite and hematite coatings developed and contributed to the partial preservation of the original porosity. Samples were divided into three groups based on petrographic observations, magnetic data and type of iron-bearing minerals. Group 1 and Group 2 samples consist of subarkoses with variable amounts of coating of microcrystalline quartz. Besides, the mineral matrix in Group 2 samples contains paramagnetic iron-bearing minerals such as Fe-dolomite, siderite and pyrite, besides Fe-illite. Samples from Juruá Formation form the Group 3 and consist of hematite-coated sandstones. Macroporosity for these samples is indicated by a peak above 0.1 s in NMR T2 time distributions, whereas intermediate peaks in the range of 0.1–0.01 s are generally related to the secondary porosity generated by mineral dissolution. Group 2 and Group 3 samples present significant shifts of the highest T2 peaks towards shorter times. These shifts are directly related to the magnetic mineralogy of the rocks (paramagnetic and hematite minerals, respectively for Group 2 and Group 3 samples), with these samples presenting the highest magnetic susceptibilities. T2 displacements in the studied samples are caused mainly by relaxitivity related to the Fe cements and the strongly magnetic hematite coatings. The diffusion coupling caused by coatings does not influence significantly the NMR response. We note that magnetite impurities are not enough to influence the diffusion relaxivity neither the NMR porosity estimates, however the localization of hematite at the pores surfaces of Group 3 samples lead to an underestimation of the porosity.

Cross-scale characteristics of backfill material using NMR and fractal theory

Abstract This paper analyzed the pore structure, quantified the pore fractal dimension, calculated the grading index (GI) of mixed aggregate, and studied the relationship among GI, pore structure, and strength to describe the cross-scale characteristics of backfill, which is made from stone powder and cemented tailing. A series of experiments were conducted on stone powder cement tailings backfill (SPCTB). The GI formulas for mixed aggregates, containing stone powder and tailings, were derived based on the Fuller theory. The nuclear magnetic resonance (NMR) fractal dimensions of backfills were derived using fractal geometry principles. Compared to the mesopore and macropore fractal dimensions, the correlation between micropore fractal dimension and macro-properties in terms of NMR porosity, pore structure complexity, uniaxial compression strength (UCS), and GI is the most significant. Macropore fractal dimension is generally correlated with UCS and GI and the other properties such as the shape of mixed aggregates also have an impact on fractal dimension. However, mesopore fractal dimension has no obvious relationship with macro-properties. Finally, the relationship between GI and UCS was studied, which contributed to improving backfill’s strength and optimizing gradation.

Effect of paramagnetic mineral content and distribution on nuclear magnetic resonance surface relaxivity in organic-rich Niobrara and Haynesville shales

Surface relaxivity is required to convert nuclear magnetic resonance (NMR) relaxation times to pore size distributions (PSD). In current practice, a constant value of surface relaxivity is used for an entire well, formation, or rock type, regardless of compositional and textural variations. The presence and distribution of paramagnetic minerals can affect surface relaxivity and, in turn, result in significant errors in PSD calculations. We present surface relaxivity calculations for two organic-rich formations, namely the Niobrara and the Haynesville formations. Surface relaxivity was calculated from surface to volume ratio and comparison of average pore radius measurements. We measured the transverse (T2) relaxation time with a low field (2 MHz) NMR instrument, porosity and PSD using nitrogen adsorption (N2) data, total specific surface area from N2 data and from cation exchange capacity (CEC), and mineralogy from X-ray diffraction (XRD). We find that surface relaxivity is linearly correlated with paramagnetic clay content, specifically chlorite and illite-smectite distributed in the matrix. The presence of smectite clay minerals increases uncertainty in surface to volume ratio and consequently in surface relaxivity calculations. Our surface relaxivity – clay correlations could be applied for surface relaxivity calculations from mineralogy and to invert NMR logs and laboratory data to PSD.

Micropore structure characteristics and quantitative characterization methods of lacustrine shale-A case study from the member 2 of Kongdian Formation, Cangdong sag, Bohai Bay Basin

To better understand the micropore characteristics of lacustrine shale and develop quantitative methods for characterizing lacustrine shale, the reservoir space types, structures and spatial distribution patterns of effective pores in the shale of Member 2 of Kongdian Formation in Cangdong sag are studied using cores, thin sections, scanning electron microscopy (SEM), confocal laser scanning microscopy (CLSM), nuclear magnetic resonance (NMR), whole-rock X-ray diffraction (XRD) data, etc. Various shale porosity calculation methods are evaluated. The study results show that the reservoir spaces of the shale mainly include three types, i.e., matrix pores, organic pores and fractures. Flaky pore throats formed by dissolution-induced pores and mould pores can improve the pore connectivity. NMR effective porosity of the shale varies from 0.59% to 4.42% with an average of 2.38%, accounting for 49.54% of the total NMR porosity and 34.53% of the gas porosity. The shale is divided into the unimodal-type felsic shale, bimodal-type felsic shale, carbonate shale and mixed shale. The different lithologies exhibit linear correlations among NMR, gas and effective porosities. The shale has effective porosity of 0.56%–4.53% with an average of 2.12%. Furthermore, the shale reservoir is divided into four classes: Class I reservoir with effective porosities of more than 2.5%; Class II1 reservoir with effective porosity of 2.0%–2.5%; Class II2 reservoir with effective porosity of 1.5%–2%; and Class III reservoir with effective porosity of less than 1.5%.

The variation characteristics of micro-pore structures of underground rocks in cold regions subject to freezing and thawing cycles

In order to investigate the evolution characteristics of the microscopic pore structures of the rocks in the underground cavities subject to freezing and thawing cycles, in this article, we conducted several rounds of freezing and thawing cyclic tests and detected the rock samples after each round of freezing and thawing cycles by means of nuclear magnetic resonance (NMR) and CT scanning. Based on the acquired NMR T2 relaxation time spectra, porosity variations, pore distributions, and imaging results of the rock samples at different freezing and thawing stages, the effects of the number of freezing and thawing cycles on the rock’s NMR T2 spectra, porosity, and microscopic pore structures were analyzed. Results show that, for the rock sample collected from the underground cavities, the micro-pore structures were significantly affected by the number of freezing and thawing cycles. More freezing and thawing cycles resulted in larger porosity and higher damage degree of the rock samples. The present study helps to unveil the evolution characteristics of the micro-pore structures of the rock samples in underground cavities after freezing and thawing cycles, and thus provides theoretical basis for the damage mechanisms and stability analysis of underground rocks in cold regions.

Insight into the Pore Characteristics of a Saudi Arabian Tight Gas Sand Reservoir

The petrophysical characterization of tight gas sands can be affected by clay minerals, gas adsorption, microfractures, and the presence of high-density minerals. In this study, we conducted various petrophysical, petrographic, and high-resolution image analyses on Saudi Arabian tight sand in order to understand how a complex pore system responds to measurement tools. About 140 plug samples extracted from six wells were subjected to routine core analyses including cleaning, drying, and porosity–permeability measurements. The porosity–permeability data was used to identify hydraulic flow units (HFU). In order to probe the factors contributing to the heterogeneity of this tight sand, 12 subsamples representing the different HFUs were selected for petrographic study and high-resolution image analysis using SEM, quantitative evaluation of minerals by scanning electron microscope (QEMSCAN), and micro-computed tomography (µCT). Nuclear magnetic resonance (NMR) and electrical resistivity measurements were also conducted on 56 subsamples representing various lithofacies. NMR porosity showed good agreement with other porosity measurements. The agreement was remarkable in specific lithofacies with porosity ranging from 0.1% to 7%. Above this range, significant scatters were seen between the porosity methods. QEMSCAN results revealed that samples with &lt;7% porosity contain a higher proportion of clay than those with porosity &gt;7%, which are either microfractured or contain partially dissolved labile minerals. The NMR T2 profiles also showed that samples with porosity &lt;7% are dominated by micropores while samples with porosity &gt;7% are dominated by macropores. Analysis of the µCT images revealed that pore throat sizes may be responsible for the poor correlation between NMR porosity and other porosity methods. NMR permeability values estimated using the Shlumberger Doll Research (SDR) method are fairly correlated with helium permeability (with an R2 of 0.6). Electrical resistivity measurements showed that the different rock types fall on the same slope of the formation factors versus porosity, with a cementation factor of 1.5.

The logging recognition of solid bitumen and its effect on physical properties, AC, resistivity and NMR parameters

Abstract Solid bitumen not only strongly damages the reservoir properties, but it is easily confused with oil and gas in the conventional classification logging interpretation, which seriously affects the effective recognition of oil and gas. Thus, it leads to a deceptive estimation of the reserve. Focusing on the above problems, this study takes Jurassic solid bitumen-containing reservoirs from the Santai-Northern Santai area in the Junggar Basin as an example, and aims to quantitatively evaluate the impact of solid bitumen on the porosity, permeability, resistivity, AC (Acoustic) and NMR (Nuclear Magnetic Resonance), with a comparison between the values of these parameters before and after core bitumen dissolution, as well as to establish an NMR identification method for solid bitumen. The results show that solid bitumen can damage the pore structure of the reservoir and cause a reduction of porosity and permeability. The content of solid bitumen is linearly correlated with the change of porosity and permeability. After solid bitumen dissolved, the resistivity decreased, the longitudinal wave time difference (Vp) and shear wave time difference (Vs) increased, and the shear wave time difference changed noticeably. The content of solid bitumen is exponentially correlated with the change of resistivity, and linearly correlated with the change of longitudinal wave time difference and shear wave time difference. Solid bitumen had a short transverse relaxation time and a response range of 10–1000 μs (Peak 1) on the T2 map. Bitumen-containing sandstone had 3 peaks on the T2 map. Peak 1 decreased, while Peaks 2 and 3 increased after the solid bitumen dissolved. Solid bitumen can be characterized by a typical short time lag of the transverse wave, a bigger density porosity than the NMR porosity and small values of T1LM and T2LM, which led to an effective recognition of the layers of solid bitumen. The results are significant for the exploration and development of oilfields.

Nuclear magnetic resonance simulations of nano-scale cores and microscopic mechanisms of oil shale

The mineral composition and pore structure of organic shale are complex, and studies of the porosity, seepage characteristics, and pore structure by using nuclear magnetic resonance (NMR) can be of great significance for the identification and quantitative evaluation of shale oil reservoirs. In particular, pore-scale NMR numerical simulations and core NMR experimental analyses of organic shale can provide a theoretical basis for NMR log interpretations. An ideal digital core and actual shale digital core were constructed by simulating the deposition process and using computerized tomography (CT) scanning, respectively. Then, one- and two-dimensional NMR numerical simulations were carried out by random-walk method to study the NMR responses of cores under different compaction and water saturation conditions. The microscopic NMR numerical simulations showed that as the degree of compaction increased, the porosity of the cores decreased, amplitudes of the T2 distributions decreased significantly, and T2 distributions moved toward the direction of short relaxation. As the echo spacing decreased, the T2 distributions shifted to the left, smaller pores were measured, and NMR porosities of shale increased; these findings are consistent with those of the rock NMR experiments. In two-dimensional T2–D maps, the signal of the wetting fluid deviated from its free diffusion coefficient line, which was indicative of restricted diffusion in tight rock. The restricted diffusion effect of water was larger than that of oil. These microscopic numerical simulations provide a physical basis for interpreting NMR macroscopic responses, and the simulated NMR responses should be helpful for fluid typing in oil shale.

Experimental investigations into stress sensitivity in three Chinese coal samples by NMR

ABSTRACT The coal reservoirs have low mechanical strength and strong stress sensitivity. The study of stress sensitivity is of great significance to the efficient development of coalbed methane (CBM). In order to reveal the stress and strain characteristics of coal reservoirs, the low-field nuclear magnetic resonance (NMR) experiments with variable confining pressures were carried out on three coal samples from China. Based on the T2 spectrum of coal samples under different confining pressures, the pore distribution, connectivity, and porosity variation rules of the coal samples were analyzed. Results show that the peaks of mesopore, macropore-fissure in the coal samples are well developed; however, the micropore peaks are poorly developed. There are differences in the stress deformation of pores and fractures in coals. With increasing confining pressures from 0 to 16 MPa, the peak of fractures decrease most obvious, and the peak of mesopore and macropore-fissure are relatively obvious, while the peak of the small pores is not significantly reduced. With the confining pressure increases, the total NMR porosity of coal decreases as the rule of negative exponential function, which is mainly controlled by changes of the porosity of seepage pore. The effect of adsorption pore on porosity changes is not obvious.