Nuclear Magnetic Resonance Porosity Research Articles

Learnings From Impact and Implications of Signal-To-Noise in NMR T1-T2 Logging of Unconventional Reservoirs

We study the impact of signal-to-noise ratio (SNR) on nuclear magnetic resonance (NMR) T1-T2 maps across data sets acquired in multiple wells of an unconventional field under various logging and processing conditions. The mean and standard deviation of NMR porosity error between continuous moving-pass and stationary measurements are used to obtain insights into the impact of SNR on accuracy and precision. In a proof-of-concept experiment, we introduce a novel semi-analytical smeared-peak (SASP) technique that compensates for the over-regularized smearing due to poor SNR, of T1-T2 relaxation responses of different fluids. The SASP approximation to de-smear volumes of different fluid types is validated with field measurements from multiple wells. The uplift of the SASP technique in improving fluid volume interpretations is apparent in the in-situ calibration of low-SNR moving-pass NMR measurements with high-quality stationary measurements. The learnings show that logging protocols that are designed to increase SNR by combining specific acquisition parameters with processing strategies, within acceptable compromises, are mandatory for reliable NMR characterization of unconventional reservoirs.

Applicability of Nuclear Magnetic Resonance Experiment in Analyzing Pore and Fluid Distribution Characteristics of Tight Sandstone: A Case Study in the Julu Area, Bohai Bay Basin, China.

Characterizing the pore and fluid distribution is critical for evaluating the reservoir potential of new areas. Nuclear magnetic resonance (NMR) is considered as an experimental method capable of full-scale characterization of pore characteristics. However, the T2 spectrum of a saturated sample is affected by a combination of sample and experimental parameters, and it is important to confirm whether the T2 spectrum fully reflects the sample pore information. Eight tight sandstone samples from the Julu area were selected for thin section identification, mercury intrusion porosimetry (MIP), NMR, NMR cryoporometry (NMRC), and centrifugation experiments to critically analyze the applicability of the NMR results. Two methods, the similarity method and Kozeny's equation method, were used to calculate surface relaxivity, a critical parameter for converting NMR T2 signals into pore information. The discussion focuses on the applicability of the calculated surface relaxivity and the phenomenon of T2 signal changes in a short relaxation range after centrifugation. The main results are as follows: The surface relaxivity values calculated using the different methods differed significantly. The surface relaxivity calculated using the same method reflected the relative magnitude of the true surface relaxivity of the samples. For the samples with large surface relaxivity, there may be partial misses of the short relaxation signal, the NMR porosity was smaller than the gas-measured porosity, there was a variation in the T2 spectrum in the short relaxation range after centrifugation, and the calculated surface relaxivity was small. The surface relaxivity calculated using Kozeny's equation was nearly accurate, but perhaps smaller than the true value. The T2 spectra mainly reflected macropore information. This study suggests that PSDs converted from T2 spectra of saturated samples should be judged with relative caution rather than solely based on the peak or range correspondence between the two curves, and the minimum centrifugal radius can be used as a constraint.

Study of nuclear magnetic resonance response mechanism in shale oil and correction of petrophysical parameters

Shale oil reservoirs, characterized by a low porosity, complex mineral composition, and heterogeneity of organic matter distribution, are common unconventional oil and gas reservoirs. Nuclear magnetic resonance (NMR) methods have great potential for the evaluation of petrophysical parameters in porous rocks. However, it is challenging to characterize the petrophysical properties of shale oil due to the complex mineral composition and heterogeneity of organic matter distribution. In this paper, a new NMR relaxation theory for shale was proposed for the first time, and the frequency dependencies of transverse surface relaxivity and internal magnetic field gradient for pore fluids were presented. The accuracy was verified by the extraction experiments, gas chromatography experiments, and multi-frequency NMR experiments for the first time. These experiments were also utilized to determine the transverse surface relaxivity and the transverse bulk relaxation time. Subsequently, the effects of the pyrite and clay minerals on shale oil T2 distributions at different instrument frequencies were analyzed with random walk simulations based on digital core technology for the first time. The results show the echo spacing, instrument frequency, pyrite content, and clay minerals are important parameters affecting the NMR response. Compared with the oil in organic pore, these factors have a greater impact on the NMR response characteristics for water in inorganic pore. When the content of pyrite is 5.3 % and the echo spacing is 0.2 ms, the numerical simulation results show that the NMR porosity of water in inorganic pore is 65.3 %, 12.3 %, and 1.6 % of the real porosity at the instrument frequencies (IF) of 2 MHz, 21.36 MHz, and 200 MHz, respectively. When chlorite with high magnetic susceptibility exists near the formation pores, it can also affect the NMR response of shale oil. The results show the effects of these factors on porosity and T2ML are non-negligible. The cross-plots of petrophysical parameters correction from shale oil T2 distributions were established for the first time. This work provides a theoretical guide for the NMR-based shale oil evaluation, which may be helpful for petrophysical parameter conversion between downhole and laboratory NMR instruments.

Impact of H2-CH4 mixture on pore structure of sandstone and limestone formations relevant to subsurface hydrogen storage

Subsurface Hydrogen (H2) storage is a promising technology to achieve net-zero carbon emissions. Depleted gas reservoirs can provide safe storage of hydrogen in the long term, and effective recovery during the cycling process. The pre-existing Methane gas (CH4) or its traces in these formations can mix with the injected hydrogen and might cause in-situ geochemical reactions with the storage rock. Despite the recent interest in evaluating H2-rock interactions, the available knowledge on the impact of H2–CH4 mixture on the petrophysical properties of storage rocks is scarce. Motivated by the lack of experimental work that exists on this topic, we provide an experimental investigation on the reactivity of sandstone and limestone formations to H2–CH4 mixture. Samples from Bandera Gray Sandstone and Indiana Limestone samples were aged in H2–CH4 mixture at 75 °C and 1400 psi for 90 days, and Nuclear Magnetic Resonance (NMR) and gas porosity analysis were performed. The results showed limited reactivity of the samples to H2–CH4 mixture, and subsequently, insignificant changes occurred in the petrophysical properties. The average porosity of BG and IL samples decreased by 3.32 % and 1.00 % respectively. NMR analysis indicates no significant changes in T2 distribution times curves, indicating no major alterations occurred in the pore structure or rock geometry. Moreover, the average NMR porosity of BG was reduced by 3 %, while the reduction of IL porosity did not exceed 6 %. We conclude that the potential geochemical reactions (dissolution/precipitation) between the H2–CH4 mixture and rock minerals are very weak within 90 days of H2–CH4 mixture treatment, thus the suitability of sandstone and limestone rocks for hydrogen storage is promising.

A study on the temperature sensitivity of NMR porosity in porous media based on the intensity of magnetization

The measurement of nuclear magnetic resonance (NMR) porosity is affected by temperature. Without considering the impact of NMR logging tools, this phenomenon is mainly caused by variations in magnetization intensity of the measured system due to temperature fluctuations and difference between the temperature of the porous medium and calibration sample. In this study, the effect of temperature was explained based on the thermodynamic theory, and the rules of NMR porosity responses to temperature changes were identified through core physics experiments. In addition, a method for correcting the influence of temperature on NMR porosity measurement was proposed, and the possible factors that may affect its application were also discussed.

Surface relaxivity estimation of coals using the cutting grain packing method for coalbed methane reservoirs

Low-field nuclear magnetic resonance (NMR) has been widely used to express the pore-size distributions of conventional and unconventional reservoirs. Based on the equation 1T2=ρFs1r, the determination of the surface relaxivity ρ can help to quantitatively convert the transverse relaxation time T2 to pore radius (r). The existing calculation of ρ using NMR requires supplementary and expensive destructive or non-destructive methods, and consolidated cylinders are required as samples to be well tested. However, the operation of multiple drilling projects and the production of many drilling cuttings are barriers to making rapid measurement of the ρ value of the unconsolidated coal cuttings challenging. In this study, an NMR grain packing method is proposed using different coal grains. The surface-to-volume ratio was transformed into the ratio of the derivative of an arbitrary pore volume to its volume, and the governing NMR equation was established by considering only the NMR porosity and T2 distribution. Sphere and cubic-like models were also constructed. The results showed that the coal with different grain sizes had different relaxation responses, and the different assemblies with the same wgrain/wgrain,c also exhibited some relaxation differences, which might be affected by the diversity in grain packing patterns and grain morphology, resulting in the variation in porosity. In addition, the water film distribution on the grain surface and the soluble minerals in the coal contribute to the variation in ρ values by influencing the relaxation properties of the voids between grains and the pores in the grains. The T2 spectrum indicated that the macropores contributed the most to the porosity, owing to the loose grain packing, and the larger grains might not strictly obey the fast diffusion limit. For the sphere-like model, the ρ values of the Ji15 and Ji17 coals were in the range of 19.47–44.04 μm/s and 36.50–46.66 μm/s, respectively; whereas for the cubic-like model, the corresponding ρ values of these two coals ranged from 24.16 μm/s to 54.64 μm/s and from 45.29 μm/s to 57.90 μm/s, respectively. Finally, different methods of ρ calculation are compared, and its potential field application is discussed.

NMR-Based Analysis of Fluid Occurrence Space and Imbibition Oil Recovery in Gulong Shale

The Gulong shale oil reservoir is situated in freshwater to slightly saline lacustrine basins mainly consisting of a pure shale geological structure, which is quite different from other shale reservoirs around the world. Currently, the development of Gulong shale oil mainly relies on hydraulic fracturing, while the subsequent shut-in period for imbibition has been proven to be an effective method for enhancing shale oil recovery. To clarify the characteristics of the fluid occurrence space and the variation in the fluid occurrence during saltwater imbibition in Gulong shale, this paper carried out porosity and permeability tests on Gulong shale cores and analyzed the fluid occurrence space characteristics and imbibition oil recovery based on nuclear magnetic resonance (NMR). In the porosity and permeability tests, T2 distributions were used to correct the porosity measured by the saturation method to obtain the NMR porosity. Combined with the identification of fractures in shale cores using micro-CT and the analysis of porosity and permeability parameters, it was found that the permeability of the shale cores was related to the development of fractures in the shale cores. Through the testing and analysis of T1-T2 maps of the shale cores before and after saturation with oil, it was found that the shale mainly contained heavy oil, light oil, and clay-bound water, and they were distributed in different regions in the T1-T2 maps. Finally, the T1-T2 maps of the shale cores at different imbibition stages were analyzed, and it was found that saltwater mainly entered the minuscule inorganic pores of clay minerals during the imbibition process and squeezed the larger-sized inorganic pores containing light oil through the hydration expansion effect, thus expelling the light oil from the shale core and achieving the purpose of enhanced oil recovery.

Laboratory NMR Study to Quantify the Water Saturation of Partially Saturated Porous Rocks

Abstract The low-field nuclear magnetic resonance (NMR) technique is widely used as a noninvasive method to characterize the water content of subsurface porous media, such as aquifers and hydrocarbon reservoirs, but the quantitative correlation between the water saturation and the NMR relaxation signal has not been fully addressed. We conducted a laboratory study to measure the NMR signals of sandstone samples with different water saturations and to develop an empirical model for estimating the water saturation. The partially saturatinthe irreducible water saturationg states were derived by a high-speed centrifuge. The result shows that the water saturation is proportional to the geometric mean of the transverse relaxation time and can be fitted through a power function. Moreover, it has been found that the fitting parameters vary with the porosity and exhibit similar behaviors with the parameters of the classical Archie equation. The water saturation as well as its mobility state can be estimated with the NMR signals and porosity data. The proposed method has the potential to be applied to detect and quantify the water content in vadose zones, phreatic aquifers, permafrost regions, and gas hydrate reservoirs.

Experimental insights into limestone-hydrogen interactions and the resultant effects on underground hydrogen storage

Industrial-scale underground hydrogen storage (UHS) in carbonate formations can facilitate the realization of carbon dioxide-free economy, as well as global energy security through replacement of fossil fuel with clean renewable energy. Although carbonate minerals-hydrogen-brine interactions plays significant role in residual trapping of H2 in calcite-dominated host-rock, however, there is limited information on impacts of hydrogen-brine-limestone reactions on storage potentials and sustainability of carbonate formation for long term underground hydrogen storage. To address this concern, two sisters outcrop limestone samples were saturated with 3 wt% NaCl brine (pH = 7) and pressurized with H2 for 125 days at 75 °C and 1400 psi to evaluate the hydrogen-brine-limestone reactions. The cores were scanned through X-ray computed micro-tomography (μCT) and visually inspected for modifications of pore structures through calcite dissolution and pore-filling. μCT and nuclear magnetic resonance (NMR) porosities before and after hydrogen injection were computed and the gas chromatography (GC) analysis of the effluent fluids was conducted to determine if any methane is produced from the reactions. Results showed that the extent of calcite dissolution was trivial in first limestone sample and almost insignificant in second sample. The small fraction of dissolved calcite in sample 1 resulted in slight change in NMR porosity from 18.55% to 20.96% and micro-CT porosity from 5% to 6.6% whereas the NMR and micro-CT porosities of sample 2 were almost the sample before and after hydrogen injection. No methane production and significant H2 loss was detected from GC analysis, suggesting that just teeny portion of hydrogen penetrated the limestone. The results largely suggest that UHS in carbonate reservoirs may not be significantly affected by H2/brine/limestone reactions within 125 days of hydrogen storage cycle. The study provides significant insight into the stability of carbonate rock in the presence of brine and H2 at short storage cycle during UHS.

Lamina Variation and Its Relationship with Sedimentary Facies in Alkaline Lacustrine, Permian Fengcheng Formation, Junggar Basin, Northwest China.

The Permian Fengcheng Formation in the Mahu Sag was deposited in a volcanic-alkaline lacustrine evaporative environment and contains a unique variety of fine-grained sediments. This study examines, at a millimeter-scale, the influence of sedimentary microfacies on variability of lamina quality in fine-grained sediments in the second member of the Fengcheng Formation (P1f2). The methods used include thin-section identification, X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscopy (SEM), nitrogen adsorption, and nuclear magnetic resonance (NMR). Six types of lamina were identified in two different lithofacies: fan-delta front facies (FDFF) and semideep/deep lacustrine facies (SDDLF). The laminae in FDFF are predominantly feldspar-quartz laminae (FQL), reedmergnerite laminae (RL), shortite laminae (SL), alkaline mineral laminae (AML), and chert laminae (CL). The laminae in SDDLF are predominantly FQL, RL, SL, CL, and dolomite laminae (DOL). Variations in reservoir quality, oil-bearing properties, and the fracability of laminae in different sedimentary facies are determined by the combined effects of lamina density, mineral composition, rock structure, organic matter abundance, and microfractures. Analysis of these factors indicates superior reservoir qualities in FDFF. In SDDLF, the pore structure is limited by high lamina density, chert content, and fine grain size with the NMR porosities of FQL, RL, SL, and CL being 1.32, 0.18, 0.84, and 0.39%, respectively. However, in FDFF, the combination of high organic matter content, feldspar, pyrite, and clay minerals has a superior effect on the organic matter and minerals deposited resulting in better pore structure and more storage space for shale oil. The NMR porosities of FQL, RL, SL, and CL are 2.81, 2.53, 1.80, and 1.12%, respectively. Overall, analysis of lamina variations and their relationships with sedimentary facies indicates that the reservoir in FDFF may offer more favorable targets for "sweet spot" evaluation.

Pore Size Distribution Characterization by Joint Interpretation of MICP and NMR: A Case Study of Chang 7 Tight Sandstone in the Ordos Basin

Pore size distribution characterization of unconventional tight reservoirs is extremely significant for an optimized extraction of petroleum from such reservoirs. In the present study, mercury injection capillary pressure (MICP) and low-field nuclear magnetic resonance (NMR) are integrated to evaluate the pore size distribution of the Chang 7 tight sandstone reservoir. The results show that the Chang 7 tight sandstones are characterized by high clay mineral content and fine grain size. They feature complex micro-nano-pore network system, mainly composed of regular primary intergranular pores, dissolved pores, inter-crystalline pores, and micro-fractures. Compared to the porosity obtained from MICP, the NMR porosity is closer to the gas-measured porosity (core analysis), and thus can more accurately describe the total pore space of the tight sandstone reservoirs. The pore throat distribution (PTD) from MICP presents a centralized distribution with high amplitude, while the pore size distribution (PSD) derived from NMR shows a unimodal distribution or bimodal distribution with low amplitude. It is notable that the difference between the PSD and the PTD is always related to the pore network composed of large pores connecting with narrow throats. The PSD always coincides very well with the PTD in the very tight non-reservoirs with a much lower porosity and permeability, probably due to the pore geometry that is dominated by the cylindrical pores. However, a significant inconsistency between the PSD and PTD in tight reservoirs of relatively high porosity and low permeability is usually associated with the pore network that is dominated by the sphere-cylindrical pores. Additionally, Euclidean distance between PSD and PTD shows a good positive correlation with pore throat ratio (PTR), further indicating that the greater difference of pore bodies and pore throats, the more obvious differentiation of two distributions. In summary, the MICP and NMR techniques imply the different profiles of pore structure, which has an important implication for deep insight into pore structure and accurate evaluation of petrophysical properties in the tight sandstone reservoir.

TOC estimation of shale oil reservoir by combining nuclear magnetic resonance logging and nuclear physics logging

Abstract The evaluation of source rock properties has become a vital step in logging interpretation. Total organic carbon (TOC) content is the key to estimating the quality and hydrocarbon generation potential of source rocks. In the shale oilfield of the Junggar Basin, the conventional method of calculating the TOC of hydrocarbon source rocks cannot satisfy logging evaluation requirements. This paper predominantly deals with a method for the quantitative estimation of TOC in source rocks via nuclear physics and nuclear magnetic resonance (NMR) logs. According to this method, the total hydrogen index of the source rock is the sum of the response of kerogen, clay minerals and fluid, expressed by corrected neutron porosity. The hydrogen index of fluid and clay minerals is indicated by the effective porosity of NMR and the estimated clay content, respectively. To eliminate the hydrogen index of fluid, the effective NMR porosity is subtracted from the corrected neutron porosity. On this basis, a new and overlapping method suitable for clay-rich rocks and oil reservoirs is proposed. This method was developed by overlaying the scaled clay content curve on the hydrogen index curve. In non-source rocks, the two curves regularly overlap. However, in organic-rich rocks the two curves will separate. The separation distance between the two curves was used to estimate TOC continuously. Possessing sound application and benefiting from the measured results of sweet spots, this method provides new insights for TOC quantitative prediction in shale oil reservoirs.

Formation Evaluation Using NMR, Mud Gas, and Triple-Combo Data – A Norwegian Logging-While-Drilling Case History

The presence of gas in hydrocarbon reservoirs has a distinct effect on commonly used porosity logging measurements such as density, neutron, and nuclear magnetic resonance (NMR). Although the effect of gas on NMR measurements is well understood, it remains difficult to estimate true formation porosity and hydrocarbon (HC) saturation exclusively from NMR data in gas-bearing formations. The hydrogen index (HI) of gas is much smaller than one and causes an underestimation of the measured NMR porosity. Unless temperature, pressure, HC composition, and saturation in the volume sensed by NMR are known accurately, compensating for the effect of gas is not easily accomplished. This paper compares different approaches for NMR gas zone analysis, and it introduces a new method integrating NMR logging data with a HI curve derived from mud gas surface logging. The results are connected to a full and consistent petrophysical reservoir description. Data and results from two wells drilled in a North Sea clastic reservoir are presented. The reservoir is dominated by thick units of sandstone, deposited in a submarine turbidite fan, with high porosity and high permeability. The wells were logged with triple-combo (i.e., gamma ray, density, neutron, and resistivity), NMR, and formation tester (FT) tools while drilling across gas, oil, and water intervals. Basic mud gas data are available from surface logging. Uncorrected NMR porosity shows an average porosity underestimation of 6 p.u. in the gas zone compared to triple-combo computer-processed interpretation (CPI) processing. The standalone evaluation of NMR data by a T2 cutoff approach and dual wait-time (DTW) data processing reduces the average porosity mismatch but results in zones of under- and overcorrection of the gas effect. Combining NMR DTW data with density improves the results and reduces the average porosity mismatch to less than 2 p.u. Compositional information from the mud gas data validates an inferred trend of fluid property variation in gas and oil zones across the reservoir and is used to derive a continuous HI log for further improving porosity and gas saturation estimation. Complementary to the results of the integrated data evaluation, we show independent results from mud gas data evaluation using a recently implemented method that provides independent porosity, permeability, and saturation indexes. Adverse conditions for the different approaches, including invasion, variations in mineralogy, and the limited vertical resolution of mud gas data, are discussed. Finally, the benefits and potential of combining NMR, mud gas, and triple-combo data are summarized.

Macro-Micro Study on Mechanical Properties of Frozen Fine Sandstone Based on DEM Mathematical Model

The study of freezing rock mechanical properties is getting more and more urgent because of coal mine construction in western China. Particle discrete element method (DEM) can describe discontinuous medium problem mathematically. In order to reveal the mechanical failure mechanism of frozen fine sandstone, the uniaxial compressive strength test of frozen fine sandstone was carried out, and then, DEM was used to simulate the uniaxial test of frozen fine sandstone. Furthermore, the nuclear magnetic resonance (NMR) technology was used to obtain pore distribution of the freezing sandstone. Finally, the results of NMR test and discrete element simulation were combined to reveal the microscopic mechanism of mechanical change in freezing fine sandstone. The DEM results show that the strength of frozen fine sandstone increases with the decrease of temperature. With the decrease of temperatures, strain softening occurs in frozen sandstone, which indicates that the discrete element simulation results are in good agreement with the uniaxial test results. Therefore, DEM can be used to simulate the mechanical behavior of frozen fine sandstone. At the same time, the DEM results also indicate that the formation and development of the shear band are the precursor of the failure of the sample. Furthermore, the NMR test confirms that temperature has a great impact on the pore distribution of sandstone. With the decrease of temperature, the pore ice content increases greatly, which induces a great decrease in NMR porosity and a vast decrease in the proportion of large and medium pores in all pores. Meanwhile, with the growth of the cohesion induced by increasing ice content, the uniaxial compressive strength increases macroscopically.

Evaluation of slim-hole NMR logging for hydrogeologic insights into dolostone and sandstone aquifers

This study assesses the performance and limitations of slim-hole borehole nuclear magnetic resonance (NMR) technology from a hydrogeologic perspective in fractured, porous rock. NMR logging was carried out in dolomitic and sandstone bedrock boreholes at two research test sites in Ontario, Canada, where aquifer and aquitard units provide a range of clay contents as well as a variety of primary and secondary porosity types (e.g. discrete fractures, reefal structures, vugs and karstic conduits). Results were compared to core measurements, geophysical logs, and hydrogeophysical testing. The vertical response curve of the instrument tested was found to produce 60% of the signal from within a 0.2m span surrounding the measuring point. The repeatability of the total porosity measurements in stationary mode is excellent where the porosity is greater than 0.15. Below that threshold, repeatability is scattered at ±0.05 porosity about the mean, with the variability primarily within the clay- and capillary-bound fractions. The NMR porosity estimates agreed with core measurements to within ±0.04 porosity in both the dolostone and sandstone, but the correlation deteriorates in finely bedded lithologies, and where fracturing is present. Much of the discrepancy is attributed to scaling in a finely layered geologic sequence, as the core samples are much smaller than the entire volume measured with NMR probes. Data collection with the probe in motion (continuous logging) added variability to the response when compared to stationary recordings. Although broadscale trends were comparable, the details and depth-specific insights of the bound fluid fractions varied with logging rates. Overall, NMR provides a robust measurement of the bulk matrix porosity and pore size distribution of lithologies intersected, both of which are critically important parameters in understanding hydrogeologic conditions and contaminant distributions in layered sedimentary rock systems.

The in-situ NMR evidence of gas hydrate forming in micro-pores in the Shenhu area, South China Sea

Nuclear magnetic resonance (NMR) measurement could provide information during the formation and dissociation of gas hydrate on the pore structure properties which are of great important to understand the gas production behavior. In this study, the in–situ NMR and other well logging data achieved during the natural gas hydrate drilling program were used to study the pore size and hydrate formation properties in the Shenhu area, South China Sea by comparing transverse magnetic relaxation time (T2) distributions between the gas hydrate zone and the upper water–saturated zone whose properties represent the virgin status. Compared with those of the upper water–saturated layer, increasing resistivity, higher–than–baseline shear modulus, less–than–density–porosity NMR porosity, shortening T2 peak time, reducing amplitude and covered area of T2 distributions and decreasing water–filling pore size denote the association of hydrate. Based on eight bin porosities distribution derived from user-defined time intervals of the T2 distribution for researching the hydrate formation characteristic in different pore size, macro–pores (T2 ≥ 10 ms, rc≥ 0.9 μm), meso–pores (3 ms ≤ T2 < 10 ms, 0.27 μm ≤rc<0.9μm) and micro–pores (T2 < 3 ms, rc< 0.27 μm) were divided. It was found that the meso–pores are the dominant pore size in the Shenhu area, but hydrate form more easily in the macro–pores. Just as the previous experience, gas hydrate forms primarily in macro–pores and meso–pores resulting in an increase of micro–pores. In addition, another mode was achieved that gas hydrate forms in the three types of pore spaces leading to a decrease of micro–pores. Both forming modes can develop reservoirs with high hydrate saturation that can exceed 30%.

Influencing mechanics and correction method of nuclear magnetic resonance measurement in igneous rocks reservoir

Nuclear magnetic resonance (NMR) measurement provides lithology-independent porosity and pore structure for sedimentary reservoirs. Recently, oil and gas were discovered in igneous rock formations, however, NMR logging porosity is substantially lower than the true porosity, and the T2 distributions does not characterize the pore-size distributions. These observations limit the use of NMR logging in igneous rock formations and new research is needed to be developed. To address this gap in the literature, using numerical simulation of NMR behavior, we conduct a theoretical study to examine the impact of magnetic susceptibility, echo spacing, and fluid type on the T2 distributions in igneous rock. The simulation results and laboratory experiment show that, the paramagnetic minerals affect the magnetization of fluids in pores and rate of the echo decay, and NMR porosity is thus significantly reduced. To effectively correct the NMR measurement, a new approach is proposed to improve the underestimation of NMR porosity and T2 distribution shifting to shorter times. For a pore model, the corrected porosity and T2 distribution are both in good agreement with the model. In a case study from Chepaizi area of Junggar Basin, China, the corrected NMR porosity matches well with core measurement, and the corrected T2 distribution shifts to longer times more than before. Moreover, bound fluid volume and movable fluid volume are both corrected, and the NMR permeability also agrees well with core laboratory measurement, which proves that the correction method effective. Therefore, this technology enables NMR log for evaluating the igneous rock reservoir quality.

Assessment of natural gas hydrate reservoirs at Site GMGS3-W19 in the Shenhu area, South China Sea based on various well logs

To obtain the characteristics of the gas hydrate reservoirs at GMGS3-W19, extensive geophysical logging data and cores were analyzed to assess the reservoir properties. Sediment porosities were estimated from density, neutron, and nuclear magnetic resonance (NMR) logs. Both the resistivity and NMR logs were used to calculate gas hydrate saturations, the Simandoux model was employed to eliminate the effects of high clay content determined based on the ECS and core data. The density porosity was closely in agreement with the core-derived porosity, and the neutron porosity was higher while the NMR porosity was lower than the density porosity of sediments without hydrates. The resistivity log has higher vertical resolution than the NMR log and thus is more favorable for assessing gas hydrate saturation with strong heterogeneity. For the gas hydrate reservoirs at GMGS3-W19, the porosity, gas hydrate saturation and free gas saturation was 52.7%, 42.7% and 10%, on average, respectively. The various logs provide different methods for the comprehensive evaluation of hydrate reservoir, which supports the selection of candidate site for gas hydrate production testing.©2022 China Geology Editorial Office.

Hydraulic Conductivity from Nuclear Magnetic Resonance Logs in Sediments with Elevated Magnetic Susceptibilities.

This study examined the application of slim-hole nuclear magnetic resonance (NMR) tools to estimate hydraulic conductivity (KNMR ) in an unconsolidated aquifer that contains a range of grain sizes (silt to gravel) and high and variable magnetic susceptibilities (MS) (10-4 to 10-2 SI). A K calibration dataset was acquired at 1-m intervals in three fully screened wells, and compared to KNMR estimates using the Schlumberger-Doll research (SDR) equation with published empirical constants developed from previous studies in unconsolidated sediments. While KNMR using published constants was within an order of magnitude of K, the agreement, overprediction, or underprediction of KNMR varied with the MS distribution in each well. An examination of the effects of MS on NMR data and site-specific empirical constants indicated that the exponent on T2ML (n-value in the SDR equation, representing the diffusion regime) was found to have the greatest influence on KNMR estimation accuracy, while NMR porosity did not improve the prediction of K. KNMR was further improved by integrating an MS log into the NMR analyses. A first approach detrended T2ML for the effects of MS prior to calculating KNMR , and a second approach introduced an MS term into the SDR equation. Both were found to produce similar refinements of KNMR in intervals of elevated MS. This study found that low frequency NMR logging with short echo times shows promise for sites with moderate to elevated MS levels, and recommends a workflow that examines parameter relationships and integrates MS logs into the estimation of KNMR .

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.