Nuclear Magnetic Resonance T2 Research Articles

1D and 2D Nuclear magnetic resonance (NMR) relaxation behaviors of protons in clay, kerogen and oil-bearing shale rocks

Abstract Few 1D T2 and 2D T1-T2 Nuclear magnetic resonance (NMR) studies have focused on oil-bearing shales with complex constituents and a deeper understanding of the NMR relaxation behaviors of oil confined in shale is needed. In this paper, a series of T2 and T1-T2 NMR experiments were performed on oil-bearing shale and its components (clay minerals and kerogen) to obtain the T1-T2 fluid typing chart and analyze the adsorbed and free oil in shale. The results were as follows: five types of water (bound, adsorbed, free, crystal and structural water) in clay minerals were qualitatively identified and described by the specific T2 to T1/T2 ratio values, and T1-T2 maps were used to qualitatively indicate the clay type. The T1-T2 fluid typing chart containing the signatures of 8 proton populations in oil-bearing shale was defined and included bulk liquid, macropore (>1000 nm) oil, nanopore (

Predicting oil saturation of tight conglomerate reservoirs via well logs based on reconstructing nuclear magnetic resonance T2 spectrum under completely watered conditions

Abstract Due to complex lithology, strong heterogeneity, low porosity and permeability; resistivity logging faces great challenges in oil saturation prediction of tight conglomerate reservoirs. First, 10 typical core samples were selected to measure and analyse the porosity, permeability, nuclear magnetic resonance (NMR) T2 spectrum and mercury injection capillary pressure (MICP) curve. Second, an empirical method was proposed for reconstructing the NMR T2 spectrum under completely watered conditions using MICP curve based on the ‘three-piece’ power function. The parameters of different models were calibrated via experimental data analysis, respectively. The 180 core experimental data from an MICP curve were used as the input database. Porosity and permeability were regarded as the MICP data selection criteria to apply this model in formation evaluation. The comparison results show good application effects. Finally, to reflect oil saturation, the ratio of T2 geometric means of NMR T2 spectra under oil-bearing and completely watered conditions was proposed. Then, the quantitative relation between oil saturation and the proposed ratio was established via experimental data from the sealed cores, which established a quantitative prediction on oil saturation of tight conglomerate reservoirs. This showed a good application effect. The average relative error and the root mean square error (RMSE) of the predicted oil saturation and sealed coring measurement were around 10 and 3%, respectively. As the proposed method is only influenced by the wettability of reservoir and viscosity of oil, it is not only appropriate for the studied area, but also for other water-wet reservoirs containing light oil. It is important for identifying oil layers, calculating oil saturation and improving log interpretation accuracy in tight conglomerate reservoirs.

Estimates of blood plasma water content using portable NMR relaxometry

Although blood plasma water content (PWC) is a relevant metric for many medical diagnostic procedures, the routine clinical measurement of PWC has remained elusive. Portable nuclear magnetic resonance (NMR) offers one way to nondestructively and quickly measure PWC. Contrived pseudoplasma samples that mimic blood plasma while also allowing rigorous control over water content are used to demonstrate the role of NMR in this work. Calibration curves relating measured NMR relaxation time constants (T2 and T1) to gravimetric PWC values for a set of human lyophilized plasma samples are used to predict the PWC in porcine and model human blood plasma from respective NMR T2 and T1 values. It is shown that the T2 and T1 decay constants measured with low field NMR relaxometry correlate with the PWC values for pseudoplasma and human lyophilized plasma samples. Statistical testing of the NMR-PWC correlation model demonstrated a prediction accuracy exceeding 98%. The PWC obtained in this way was used to correct sodium cation concentrations reported from direct ion-selective electrode tests. The accuracy of PWC determination with NMR is comparable to that of the gravimetric method that requires sample lyophilization. The rapid turnaround time, non-destructive nature, and portable footprint of the NMR-PWC measurement makes rapid, point-of-care clinical electrolyte estimates possible.

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.

Classification of tight sandstone reservoirs based on NMR logging

The traditional reservoir classification methods based on conventional well logging are inefficient for determining the properties, such as the porosity, shale volume, J function, and flow zone index, of the tight sandstone reservoirs because of their complex pore structure and large heterogeneity. Specifically, the method that is commonly used to characterize the reservoir pore structure is dependent on the nuclear magnetic resonance (NMR) transverse relaxation time (T2) distribution, which is closely related to the pore size distribution. Further, the pore structure parameters (displacement pressure, maximum pore-throat radius, and median pore-throat radius) can be determined and applied to reservoir classification based on the empirical linear or power function obtained from the NMR T2 distributions and the mercury intrusion capillary pressure curves. However, the effective generalization of these empirical functions is difficult because they differ according to the region and are limited by the representative samples of different regions. A lognormal distribution is commonly used to describe the pore size and particle size distributions of the rock and quantitatively characterize the reservoir pore structure based on the volume, mean radius, and standard deviation of the small and large pores. In this study, we obtain six parameters (the volume, mean radius, and standard deviation of the small and large pores) that represent the characteristics of pore distribution and rock heterogeneity, calculate the total porosity via NMR logging, and classify the reservoirs via cluster analysis by adopting a bimodal lognormal distribution to fit the NMR T2 spectrum. Finally, based on the data obtained from the core tests and the NMR logs, the proposed method, which is readily applicable, can effectively classify the tight sandstone reservoirs.

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 <7% porosity contain a higher proportion of clay than those with porosity >7%, which are either microfractured or contain partially dissolved labile minerals. The NMR T2 profiles also showed that samples with porosity <7% are dominated by micropores while samples with porosity >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.

Reservoir characteristics and evaluation of fluid mobility in organic-rich mixed siliciclastic-carbonate sediments: A case study of the lacustrine Qiketai Formation in Shengbei Sag, Turpan-Hami Basin, Northwest China

Organic matter-rich mixed siliciclastic-carbonate sediments is a special type of tight oil reservoir in the Turpan-Hami basin, which is characterized by complex fluid type, mineral composition and pore structure. By using casting thin sections, scanning electron microscopy (SEM) and whole rock X diffraction (XRD), pore types and petrological characterization of reservoirs are analyzed. Combined with the result of the physical property, nuclear magnetic resonance (NMR) experiments, the effects of the porosity, permeability, and pore size distribution on the movable fluid distribution in the tight reservoir were evaluated. The results showed that there are four types of mixed siliciclastic-carbonate sediments reservoir, which have high TOC. The reservoirs are characterized by low porosity range from 2% to 10% and extra low permeability mainly less than 0.1 × 10−3 μm2. Nanometer scale intergranular pores and micro-fractures were the main reservoir pore types, we further divided the pore sizes distribution into two categories based on their water-saturated NMR T2 spectra: Type I (bimodal pattern) and Type II (left unimodal, micropores with a diameter less than 100 nm). The fluid components in the reservoir including water in nano-pores, movable light oil, non-movable heavy oil and bound water were analyzed using advanced NMR T1-T2 maps. The mobile light oil content in the silt-bearing argillaceous arenaceous limestone and silt-bearing lime micritic dolomite is higher than that of other lithological reservoirs. The movable light oil content exhibited a strong correlation with permeability, and the proportion of large pores, indicating that the large pores, which are mainly supplied by the intergranular pores in dolomite, substantially contributed to mobility of the hydrocarbon fluid. The non-movable heavy oil fluid component is impacted the small pores ratio and solid organic matter, while water the in nano-pores is greatly affected by clay minerals.

Nuclear-Magnetic-Resonance Study on Oil Mobilization in Shale Exposed to CO2

SummaryReservoirs in the Qian 34 10 rhythmic layer of the Qianjiang Basin are shale oil reservoirs with intersalt sediments. During the natural depletion and development process, production rate of oil decreases rapidly. Water injection and CO2 injection are potential technologies for enhanced oil recovery (EOR) in shale. Because of high salt content in formations, unsaturated water dissolves salt and damages reservoirs. CO2 does not react with salt, and CO2 injection does not damage reservoirs. Moreover, CO2 could enter the micropores of the reservoir rocks and mobilize oil by diffusion, extraction, and swelling mechanisms. To verify oil mobilization in the shale exposed to CO2, exposure experiments based on nuclear magnetic resonance (NMR) were conducted in this study.NMR T2 spectrum could reflect the oil in place and be used to calculate the oil content of rock with low permeability. In this study, 10 fresh shale samples (from six depths) were analyzed, and the oil contents were determined using NMR T2 spectra. Two of the shale samples with high oil contents were selected for the CO2-exposure experiment. At a temperature of 40°C and a pressure of 17.5 MPa, the fresh shale samples were exposed to CO2, and the NMR T2 spectra obtained were used to continuously determine the oil content of the shale. The oil mobilization in the shale exposed to CO2 was determined.The results of the NMR T2 spectra showed that the NMR volume fractions of the remaining oil in seven fresh shale samples were above 10%. The recovery of the S5# shale exposed to CO2 was 51.2% after 8 days, whereas that of the S9# shale was 55.8% after 6.1 days. These results indicated that more than half of the shale oil was mobilized during the relatively long exposure time after CO2 injection. NMR T2 spectroscopy results also showed that oil in all pores could be mobilized as the exposure time increased.This study showed the quantitative results of the CO2-injection method and EOR in a shale oil reservoir of the Qianjiang Basin. All conclusions support starting a CO2-EOR pilot project in the shale oil reservoir with intersalt sediments with ultralow permeability.

Nuclear-Magnetic-Resonance Monitoring of Mass Exchange in a Low-Permeability Matrix/Fracture Model During CO2 Cyclic Injection: A Mechanistic Study

SummaryRecent reports have demonstrated that carbon dioxide (CO2) injection can further raise the oil recovery of fractured tight reservoirs after natural depletion, with major projects in progress worldwide. There is, however, a lack of understanding of the mass-exchange process between the matrix and fracture at pore scale. In this study, a matrix (0.8 md)/fracture model was designed to experimentally simulate a CO2-cyclic-injection process at 80°C and 35 MPa (Lucaogou tight formation). The oil (dead-oil) concentration in the matrix and fracture was continuously monitored online using a low-field nuclear-magnetic-resonance (NMR) technique aiming to quantify the oil recovery in situ and clarify the mass-exchange behaviors. The results showed that CO2 cyclic injection was promising in improving the oil recovery of fractured tight reservoirs. Nevertheless, the oil-recovery rates rapidly declined with the cycle of CO2 injection and the incremental oil was primarily produced by large pores with 100 ms > T2 > 3.0 ms. The NMR T2 profiles of the model evidenced the drainage of the matrix oil by CO2 toward the fracture. Because of the light-hydrocarbon extraction, the produced oils became lighter than the original oil. We noted that the main driving forces of the incremental oil recovery were CO2 displacement, CO2/oil interactions (mainly extraction and solubility), and pressure gradient (depressurization). In the first cycle, the CO2/oil interactions driven by CO2 diffusion during soaking enhanced the mass exchange between the matrix and the fracture. However, from the second cycle, CO2/oil interactions and CO2 displacement became insignificant. The results of this study supplement earlier findings and can provide insights into the CO2-enhanced-oil- recovery (EOR) mechanisms in fractured tight reservoirs.NOTE: Supporting information available.

The Characteristics of Oil Migration due to Water Imbibition in Tight Oil Reservoirs

In tight oil reservoirs, water imbibition is the key mechanism to improve oil production during shut-in operations. However, the complex microstructure and composition of minerals complicate the interpretation of oil migration during water imbibition. In this study, nuclear magnetic resonance (NMR) T2 spectra was used to monitor the oil migration dynamics in tight oil reservoirs. The factors influencing pore size distribution, micro-fractures, and clay minerals were systematically investigated. The results show that the small pores corresponded to a larger capillary pressure and a stronger imbibition capacity, expelling the oil into the large pores. The small pores had a more effective oil recovery than the large pores. As the soaking time increases, the water preferentially entered the natural micro-fractures, expelling the oil in the micro-fractures. Subsequently, the oil in the small pores was slowly expelled. Compared with the matrix pores, natural micro-fractures had a smaller flow resistance and were more conducive to water and oil flow. Clay minerals may have induced micro-fracture propagation, which can act as the oil migration channels during water imbibition. In contrary to the inhibitory effect of natural micro-fractures, the new micro-fractures could contribute to the oil migration from small pores into large pores. This study characterized the oil migration characteristics and provides new insight into tight oil production.

Analysis of Petrophysical Characteristics and Water Movability of Tight Sandstone Using Low-Field Nuclear Magnetic Resonance

Low-field nuclear magnetic resonance (NMR) coupled with gas–water centrifugation (GWC) was performed to investigate petrophysical characteristics and water movability of the Chang 7 tight sandstone. Microscopic observation, mineral composition analysis and grain size analysis were applied to determine lithology and pore characteristics. Then, the controls of petrophysical properties and geological factors on the water movability were discussed. The results indicate that the T2 distribution of the Chang 7 tight sandstone can be divided into three groups according to the shape, range and amplitude of T2 spectrum. The removable water volume increases with the centrifugal force, but its gradient presents a remarkable difference among the different reservoir types. The final removable water volume (Φmov) at centrifuge force of 400 psi (average value of 5.28%) is approximately half of the total pore volume (porosity). The T2 geometric mean (T2gm), fractal dimension (Df) and NMR permeability calculated from NMR data can be used to characterize the pore structure and petrophysical properties of tight sandstone. The reservoir quality index can also be estimated based on the NMR permeability models. Removable water volume under the different centrifugation conditions is positively related to porosity, permeability and T2gm and negatively related to Df. Furthermore, removable water volume under different centrifugation conditions is positively related to detrital mineral (quartz + feldspar) content and grain size but negatively related to clay content.

Pore size distribution and reservoir characterization: evaluation for the Eocene beach-bar sequence, Dongying Depression, China

Pore size distribution and associated heterogeneities of thinly bedded beach-bar sandstone reservoir from upper fourth member of Eocene Shahejie Formation (Es4s) are characterized with the help of mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) transversal relaxation time (T2) data. Permeability and porosity are two represented important characteristics of rocks that control the movement and storage of fluids. The aim of this paper is to establish relationships between pore throat sizes and reservoir quality. The results derived from thin-section petrography, scanning electron microscopy (SEM), MICP, NMR T2 relaxation time, and 3D micro-CT (μ-CT) are compared to characterize pore space dimensions and types comprehensively. Average pore throat size from MICP ranges between 0.47 μm and 2.83 μm while maximum pore throat size ranges between 2.48 μm and 7.36 μm. The combination of pore size distribution obtained from MICP and NMR seems appropriate to cover the range of pore size from beach-bar sand and overcome the individual method limits. Afterwards, digital 3D μ-CT tomographic images are used to characterize and visualize pore space and pore network model to compare with the experimental data. MICP and NMR experiment showed generally bimodal (meso and micro) pore size distribution. Usually mesopore corresponding to intergranular pores is dominant, while heavily cemented sandstones show large amounts of intercrystalline micropores. Complex and heterogeneous beach-bar sandstone reservoir requires comprehensive study program to evaluate the reservoir.

Direct NMR T1 distribution measurement without using ill-posed fitting methods.

The usual Nuclear Magnetic Resonance (NMR) experiments for measuring spin-lattice relaxation time (T1) distributions are Inversion-Recovery (IR) and Saturation-Recovery (SR), followed by data processing based on ill-posed multi-exponential curve fitting methods. Recently, a new method combining SR and IR, called Saturation-Inversion-Recovery (SIR), has been proposed to obtain sharper T1-dependences than IR and SR. In this article, we propose an appropriate combination of SIR signals to directly obtain T1 distributions without using any multi-exponential fitting methods.

Weighted iterative inversion method for T2 spectrum in nuclear magnetic resonance

In traditional nuclear magnetic resonance T2 inversion methods, the components with long T2 absorb the components with short T2, especially for low magnetic field intensity. As a result, the true distribution of all components often cannot be reflected by their solutions, and thus obtaining short T2 components is an important T2 inversion problem. Herein, a weighted iterative inversion method for T2 spectrum in nuclear magnetic resonance is proposed to solve this problem. The weight-based method is applied to ensure that the short T2 components are not eliminated. The weight scheme is determined by two parameters: the number of weights and maximum weight. The number of weights is determined by the rate of decay, and the maximum weight is mainly determined by three parameters: signal-noise ratio, curvature, and slope of collected signal. To avoid the mutations of results caused by weights, the iteration process was adopted to obtain the optimal solution. The proposed method provides good results, and it was verified to be robust and accurate though simulations and experiments.

Determination of the critical flow pore diameter of shale caprock

Abstract The breakthrough pressure and pore permeability characteristics of shale caprock are the physical response of the microscopic pore throat structure. Whether oil and gas can break through shale caprock under the action of migration force is closely related to the critical flow pore diameter (pore throat diameter) of the rock. Therefore, the critical flow pore diameter is a key parameter for the division of the reservoir and caprock and evaluation of the physical seal abilities of caprock, affecting the oil and gas migration and accumulation, which are controlled by the critical lithology. In this study, the shale caprock of the N gas reservoir of the Huagang Formation in the Xihu sag, East China Sea Basin was comprehensively studied using particle size analysis, systematic environmental scanning electron microscopy, nano-CT, digital core reconstruction, low-temperature gas adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance test for unconventional reservoir. In addition, the critical flow pore diameter of the shale caprock was determined. Based on the intersection point of the trendline of the breakthrough pressure data between the caprock and reservoir and the lower breakthrough pressure limit of the caprock of the gas–water reservoir, the breakthrough pressure limit of the caprock and reservoir is 2 MPa. Based on the correlation between the breakthrough pressure and shale lithology, the critical lithology for the division of the caprock and reservoir is argillaceous siltstone with a low breakthrough pressure limit of 2 MPa. Based on the identification of lithology boundary between caprock and reservoir, the critical lithology of the argillaceous siltstone selected as the research object, above-mentioned unconventional reservoir test technologies were carried out. The pore size statistics obtained from environmental scanning electron microscopy and the digital core model show that the critical flow pore diameter is between 100 and 300 nm. The high-pressure mercury injection test shows that the critical flow pore diameter ≥155 nm. The full pore diameter distribution curve is obtained by combined low-temperature carbon dioxide adsorption, low-temperature nitrogen adsorption and high-pressure mercury injection measurements. Compared the full pore diameter distribution curve with the nuclear magnetic resonance T2 spectrometry before and after centrifugation, the critical flow pore diameter is greater than 84 nm, ranging between 148 and 339 nm. Finally, based on the lithology, breakthrough pressure, and pore diameter relationships, the critical flow pore diameter of the shale caprock is 200 nm.

Modelling surface NMR spin-echo experiments in a heterogeneous B1 field

SUMMARY Surface nuclear magnetic resonance (NMR) measurements show great promise for characterization of subsurface water content, pore-sizes and permeability. The link between surface NMR and pore-size/permeability is founded in the connection between the NMR signal's time dependence and the geometry of the pore-space. To strengthen links between the NMR signal and pore-geometry multipulse surface NMR sequences have been developed to estimate the parameter T2, which carries a strong link to pore-geometry and has formed the basis for NMR-based permeability estimation in the petroleum industry for decades. Producing reliable subsurface characterizations from multipulse surface NMR measurements that measure T2 requires that the forward model is able to accurately predict the transverse magnetization at the time when the measurement occurs. Traditional surface NMR T2 forward models employ an analytic expression for the transverse magnetization, an expression developed in the context of laboratory NMR experiments conducted under conditions significantly different from surface NMR and which require several assumptions to simplify the underlying Bloch equation. To investigate the reliability of this analytic expression under surface NMR conditions, a synthetic comparison is performed where the analytic expression is contrasted against the transverse magnetization predicted from a solution of the full-Bloch equation without the same simplifying assumptions and which can appropriately weight heterogeneity in the applied and background magnetic fields. The comparison shows that the analytic expression breaks down in a range of conditions typical to surface NMR measurements.

Sensitive parameters of NMR T2 spectrum and their application to pore structure characterization and evaluation in logging profile: A case study from Chang 7 in the Yanchang Formation, Heshui area, Ordos Basin, NW China

Abstract The evaluation of the pore structure of tight sandstone reservoirs has a significant influence on the effective exploration and development of tight sandstone oil. Laboratory measurements including scanning electron microscopy (SEM), mercury-injection capillary pressure (MICP), gas adsorption, nuclear magnetic resonance (NMR), and Nano-CT can provide detailed pore structure data. However, only NMR results can be used to evaluate the pore structure in a logging profile due to NMR logging. In this study, the relationships between NMR T2 distribution, pore structure, and pore size of tight sandstone in Chang 7 of the Yanchang Formation, in the Heshui area of the Ordos Basin, are analyzed based on NMR principles. The characteristics of the NMR T2 distribution of different rock samples are analyzed; the sensitive parameters of the NMR T2 spectrum are proposed. These parameters are then used to classify pore structure types in tight sandstone reservoirs and divide the active layers in the logging profile of the study area. The results indicate that different pore size structures have different distributions, and that the NMR T2 spectrum can highlight the difference in the pore structure type and pore size distribution using sensitive parameters such as T2P2 (the value of T2 corresponding to the last peak of the bimodal NMR T2 spectrum) and TDM (the mean value of T2 relaxation time obtained by weighted average method). As the pore structure of the rock samples in the study area worsened, their porosity and permeability worsened, T2P2 and TDM decreased, and the displacement pressure and NMR irreducible water saturation increased. The results of classifying the pore structure types obtained in the logging profile are helpful in evaluating the effectiveness of the reservoir and in the broad application of NMR logging in terms of understanding pore structure.

Estimating irreducible water saturation and permeability of sandstones from nuclear magnetic resonance measurements by fractal analysis

Abstract Understanding the relationships between the pore structure and bulk properties such as irreducible water saturation (Swir) and permeability (k) of rocks is a crucial problem in geoscience. In this study, two types of fractal dimension were determined from nuclear magnetic resonance (NMR) T2 relaxation time distribution and models for estimating Swir and k using fractal theory were proposed. In view of the data of sandstone samples from upper Paleozoic formation in China, we found a good agreement between the predicted Swir values based on fractal analysis and the experimental measurements, and the estimated k values based on the proposed model are within one order of magnitude of measured k. Additionally, another four frequently used k estimation models were compared with our proposed model, and the result support that the proposed approach has great potential in investigating k while certain limitation still exists. This procedure was applied on another set of sandstone samples collected from a different location, and the predicted permeability values are reliable. Our study suggests that the proposed Swir estimation model using NMR T2 data and fractal dimensions provides useful insights into characterizing the pore space properties of sedimentary rocks. Our work demonstrates that we can use NMR data to infer Swir directly, and the estimated Swir value can be well integrated in permeability prediction model, which improves the applications of NMR in characterizing the properties related to rock pores.

Nuclear magnetic resonance T1-T2 inversion with double objective functions.

We report an effective and robust method for nuclear magnetic resonance (NMR) longitudinal relaxation time-transverse relaxation time (T1-T2) inversion with double objective functions. First, we develop the first objective function based on L1 regularization, proposed an effective method to choose the optimum L1 regularization parameter, and solve the objective function employing a two-step iterative shrinkage/thresholding algorithm. Subsequently, we update the kernel matrix based on the solution of the first objective function, and then develop the second objective function using the measured data and updated kernel matrix based on the least-squares principle, and we use the conjugate gradient algorithm for the first time to solve the objective function about NMR data inversion. To improve the speed of NMR T1-T2 inversion, we present a Gaussian-based random SVD method. Finally, numerical and experimental examples are done to test the robustness of the proposed inversion method. The results indicate that the proposed inversion method can effectively achieve NMR T1-T2 inversion at a low data SNR.

Origin and formation mechanisms of low oil saturation reservoirs in Nanpu Sag, Bohai Bay Basin, China

Abstract Low oil saturation reservoirs are increasingly encountered in superimposed sedimentary basins, however, the uncertainty about the origin of the low oil saturation becomes a major factor impeding further hydrocarbon exploration. Routine core analysis, (fluorescence) thin section, scanning electron microscope (SEM) and nuclear magnetic resonance (NMR) measurements were used to understand the characteristics and formation mechanisms of the low oil saturation reservoirs in the Paleogene Dongying Formation in the Nanpu sag, Bohai Bay Basin, East China. Irreducible water saturation was determined from sealed coring oil saturation testing and NMR logs. Wide ranges of porosity and permeability were observed, and the samples with moderate reservoir quality have the best oil bearing property. Low oil saturation oil layers are characterized by low oil saturation ( 40%), with only oil being produced whereas no water or only minor amounts of water being produced. The low oil saturation oil-water reservoirs refer to the low oil saturation layers in which both oil and water will be produced during oil testing. Irreducible water saturation increases with total clay content, with the authigenic clays (kaolinite, illite and mixed layer illite/smectite) blocking pore spaces, and resulting in high irreducible water saturations. Fluorescence thin sections combined with NMR measurements show that the NMR T2 (transversal relaxation time) distribution is uni-modal, with large intergranular pores being rare. Almost the entire pore-size range is oil bearing for the low oil saturation oil reservoirs. The large intergranular pores are fluorescence-free, while the intragranular dissolution pores and micropores emit fluorescence in the low oil saturation oil-water reservoirs. The NMR T2 distribution of low oil saturation oil-water reservoirs is bi-modal and right-skewed, and the main oil-bearing NMR pore size distribution ranges from 0.1 to 100 ms. High irreducible water content was encountered in the low oil saturation oil reservoirs and low oil saturation oil-water reservoirs, and only part of the large intergranular pores are oil saturated, and in some cases only the intragranular pores are saturated with oils forming low oil saturation oil reservoirs. The results help improve the knowledge of characteristics and formation of the low oil saturation oil layers, and could provide insights in enhancing oil recovery.