Nuclear Magnetic Resonance T2 Spectrum Research Articles

A method to probe the pore-throat structure of tight reservoirs based on low-field NMR: Insights from a cylindrical pore model

Abstract This research proposes a new method of estimating pore-throat size distribution that converted based on nuclear magnetic resonance (NMR) T2 spectra, so as to more accurately explore the pore-throat structures of tight reservoirs. In this work, one of the most potential shale formations, Yanchang shales in the Ordos basin, NW China, was targeted. Take Chang 2 Member as an example, the experimental parameters were comprehensively analyzed, including petrological property analysis, NMR, and constant-rate mercury injection porosimetry (MIP). This research compared the pore-throat size distributions which are converted from NMR T2 spectra using a conventional method, an empirical formula method, and the new method. The research found that the results obtained through the linear relationship of the conventional method showed low accuracy, and the fitting coefficients vary from 0.5339 to 0.8238. Although the empirical method lacks physical significance and mathematical derivation, the fitting coefficients are from 0.8565 to 0.9886, which is referable. The new method brought in the physical significance of formula derivation and took into account the distribution characteristics of experimental data, resulting in higher fitting coefficients of 0.9928–0.9999. Based on the fitting results, the new method is more reasonable and feasible, which can be used for conversion of pore-throat size distribution through NMR T2 spectrum to obtain the NMR pore-throat structure.

Experimental study on EOR by CO2 huff-n-puff and CO2 flooding in tight conglomerate reservoirs with pore scale

CO2-assisted EOR technologies appear to be low-cost and eco-friendly means to boost crude oil production of dense reservoirs. The potential of CO2 huff-n-puff process and CO2 flooding processes have been extensively investigated in tight sandstone reservoirs, while few work has been done in tight conglomerate reservoirs, which exhibit strong micro-heterogeneity. In the present work, we quantitatively investigated the potential of CO2 injection processes in tight conglomerate reservoirs under reservoir conditions (formation pressure 23 MPa, temperature 69 °C). High temperature and high pressure nuclear magnetic resonance (NMR) online monitoring system was used to pore-scale monitoring the change of oil saturation in-situ through NMR T2 spectrum, one-dimensional (1D) NMR spatial distribution of signal and two-dimensional (2D) NMR images. It was demonstrated that CO2 injection processes were applicable in target tight conglomerate reservoir with recovery factors of about 35%. The results of this study pore-scale revealed the feasibility of CO2-assisted EOR technologies in tight conglomerate reservoirs.

Effect of pore structure on oil‐bearing property in the third member of Paleogene Funing Formation in Subei Basin, East China

AbstractMercury injection capillary pressure (MICP) tests, nuclear magnetic resonance (NMR), (fluorescence) thin section, X‐ray diffraction (XRD), and scanning electron microscope (SEM) analyses were used to describe the size and distribution of entire pore‐throat structures in the sandstones of the E1f3 (the third member of Paleogene Funing Formation) in the Subei Basin. The lithologies of E1f3 in the Subei Basin are mainly dark‐gray, very fine‐grained sandstones and siltstones, interbedded with dark mudstones. The pore systems predominantly feature secondary intergranular and intragranular dissolution pores, micropores coexisting with minor amounts of intergranular pores, and microfractures. The high threshold pressure and bulk volume of irreducible fluids values and the significant variation in the NMR and MICP parameters indicate that the E1f3 reservoirs are characterized by complex and heterogeneous microscopic pore structures. Microscopic pore‐throat parameters are linked with macroscopic properties through the reservoir quality index (RQI). The NMR T2 (transverse time relaxation) spectrum is unimodal or bimodal but with weak right peaks, indicating the rarity of large intergranular pores. However, large‐scale pore throats, though only account for a minor part of the total pore volume, significantly contribute to the total permeability. The abundance of small‐scale pore‐throat systems (short T2 components) results in high irreducible water content. Therefore, the oil saturation in E1f3 sandstones is low, and the pore structure, especially the number of micropores, determines the oil‐bearing property. Oil primarily occurs in the intragranular dissolution pores with minor amounts occurring in the large intergranular pores. Most of the micropores are bound by capillary water. The sandstones with chlorite clay minerals tend to be oil‐wet and have high oil‐bearing potential, while the abundance of detrital clay or illite contributes to a low oil‐bearing grade. The combination of core and microscopic observations and the MICP and NMR analyses have allowed the determination of the pore structure characteristics and their coupling effects on oil‐bearing property.

Novel Insights into the Movable Fluid Distribution in Tight Sandstones Using Nuclear Magnetic Resonance and Rate-Controlled Porosimetry

To characterize the movable fluid distribution in tight sandstones and determine its influencing factors, 20 tight sandstone core samples from the Chang-6 and Chang-8 Members of the Yanchang Formation in the Ordos Basin, NW China, were analyzed using nuclear magnetic resonance (NMR) and rate-controlled porosimetry (RCP). The conventional method of movable fluid analysis divides the whole NMR T2 spectrum into two parts, namely unmovable and movable fluids, based on a single T2cutoff value. However, this conventional method ignores pore size wherein fluid is partially movable. In this paper, the fluid in tight sandstones is divided into three parts, i.e., completely unmovable, partially movable and completely movable fluids. Based on the throat size distribution obtained from RCP, T2 spectra were converted into corresponding pore-throat sizes with the nonlinear conversion method, and then the critical pore-throat sizes for fluid distribution were derived. The research results show that the average residual liquid saturation was 46.14% under a centrifugal pressure of 900 psi. On average, the completely unmovable fluid occupied approximately 18% of the total pore volume of tight sandstones, the partially movable fluid accounted for approximately 72% of the total pore volume, and the completely movable fluid accounted for only approximately 10% of the total pore volume. The pore throats filled with completely unmovable fluid contributed very little to the permeability. Compared with the Chang-8 Member, the tight sandstones of the Chang-6 Member had higher completely unmovable fluid saturation and larger critical pore-throat size of the completely unmovable fluid.

Insights in the pore structure, fluid mobility and oiliness in oil shales of Paleogene Funing Formation in Subei Basin, China

Abstract Pore structure is an important factor influencing reservoir properties of oil shales. Routine core analysis, thin section, scanning electron microscope (SEM), mercury injection capillary pressure (MICP) tests, Nuclear Magnetic Resonance (NMR), and computed tomography (CT) were used to provide insights into the pore throat distribution in oil shales of member 2 of Paleogene Funing Formation (E1f2) in Subei Basin, China, with the special aim to unravel the effect of pore structure on fluid mobility and oiliness. The relationships between NMR parameters, petrophysical property and capillary parameters are investigated. The results show that rock composition in the oil shales consist of quartz, feldspar, carbonate particles, clay minerals and organic matters. Pore systems consist of large-scale interparticle pores, intragranular dissolution pores, and small-scale micropores within clay minerals and the organic matter pores. Four types of pore structure (Type Ⅰ, Type Ⅱ, Type Ⅲ and Type Ⅳ) are divided according to the patterns of capillary curves, capillary parameters, NMR T2 (transverse relaxation time) spectrum and BVI (bulk volume of immovable fluid) values. From Type Ⅰ to Type Ⅳ pore structure, the maximum mercury saturation (SHgmax) and mercury extrusion efficiency are decreasing, and the SHgmax are less than 50% averagely, indicating the oil shales are characterized by very poor pore connectivity. The T2 spectrum changes from bi-modal behavior to uni-modal and the right peaks become lower or even disappearing from Type Ⅰ to Type Ⅳ pore structure. Fluid mobility is not primarily controlled by pore size, but dependent on the content of short T2 components ( Pore structure controlled fluid mobility and determined the microscopic oiliness and macroscopic oil bearing property or hydrocarbon productivity. The comprehensive study above gains insights into the microscopic pore structure and their controls on fluid mobility and oiliness in shale oil reservoirs, and this may have implications for resource potential evaluation and effective exploitation of oil shales.

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.

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.

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.

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.

Full‐Sized Pore Structure and Fractal Characteristics of Marine‐Continental Transitional Shale: A Case Study in Qinshui Basin, North China

Based on 10 shale samples collected from 4 wells in Qinshui Basin, we investigate the full‐sized pore structure and fractal characteristics of Marine‐Continental transitional shale by performing organic geochemistry, mineralogical composition, Nitrogen gas adsorption (N2 adsorption) and Nuclear Magnetic Resonance (NMR) measurements and fractal analysis. Results show that the TOC content of the shale samples is relatively high, with an average value of 2.44wt%, and the thermal evolution is during the mature‐over mature stage. The NMR T2 spectrum can be used to characterize the full‐sized pore structure characteristics of shale. By combining N2 adsorption pore structure parameters and NMR T2 spectrums, the surface relaxivity of samples are calculated to be between 1.7877 um/s and 5.2272 um/s. On this basis, the T2 spectrums are converted to full‐sized pore volume and surface area distribution curves. The statistics show that the pore volume is mainly provided by mesopore, followed by micropore, and the average percentages are 65.04% and 30.83% respectively; the surface area is mainly provided by micropore, followed by mesopore, and the average percentages are 60.8004% and 39.137% respectively; macropore contributes little to pore volume and surface area. The pore structure characteristics of shale have no relationship with TOC, but strong relationships with clay minerals content. NMR fractal dimensions Dmicro and Dmeso have strong positive relationships with the N2 adsorption fractal dimensions D1 and D2 respectively, indicating that Dmicro can be used to characterize the fractal characteristics of pore surface, and Dmeso can be used to characterize the fractal characteristics of pore structure. The shale surface relaxivity is controlled by multiple factors. The increasing of clay mineral content, pore surface area, pore surface fractal dimension and the decreasing of average pore size, will all lead to the decreasing of shale surface relaxivity.

Characterization of Pore Throat Size Distribution in Tight Sandstones with Nuclear Magnetic Resonance and High-Pressure Mercury Intrusion

Characterization of pore throat size distribution (PTSD) in tight sandstones is of substantial significance for tight sandstone reservoirs evaluation. High-pressure mercury intrusion (HPMI) and nuclear magnetic resonance (NMR) are the effective methods for characterizing PTSD of reservoirs. NMR T2 spectra is usually converted to mercury intrusion capillary pressure for PTSD characterization. However, the conversion is challenging in tight sandstones due to tiny pore throat sizes. In this paper, the linear conversion method and the nonlinear conversion method are investigated, and the error minimization method and the least square method are proposed to calculate the conversion coefficients of the linear conversion method and the nonlinear conversion method, respectively. Finally, the advantages and disadvantages of these two different conversion methods are discussed and compared with field case study. The research results show that the average linear conversion coefficients of the 20 tight sandstone core plugs collected from Yanchang Formation, Ordos Basin of China is 0.0133 μm/ms; the average nonlinear conversion coefficient is 0.0093 μm/ms and the average nonlinear conversion exponent is 0.725. Although PTSD converted from NMR spectra by the nonlinear conversion method is wider than that obtained from linear conversion method, the nonlinear conversion method can retain the characteristic of bi-modal distribution in PTSD.

Experimental investigation on the influence factors and oil production distribution in different pore sizes during CO2 huff-n-puff in an ultra-high-pressure tight oil reservoir

The Xinjiang tight oil reservoir has a low depletion recovery rate and high remaining oil content. The target reservoir has ultra-low permeability and complex pore structure. Therefore, performing water injection is very difficult, resulting in ineffective waterflooding. In this study, a series of experiments were conducted to study the effects of cycle numbers, production pressure, and permeability in CO2 huff-n-puff. The remaining oil production distribution in different pore sizes was also analyzed by the nuclear magnetic resonance (NMR) technique. The results showed that the cumulative oil recovery logarithmically increases with an increase in number of cycles, whereas, the oil recovery cycle decreases. Low production pressure and high permeability result in a higher oil recovery factor (ORF) of CO2 huff-n-puff. In addition, the optimal production pressure is 22 MPa. After the eighth cycle, the cumulative oil recovery can increase by 16.5%–44.5%, approximately 4.7–7.6 times that of the depletion recovery rate, indicating that CO2 huff-n-puff is a feasible way to enhance the ORF of a tight oil reservoir. HPR Chinaowever, the oil production in the first five cycles accounts for 84%–91.7% of the total enhanced recovery. Therefore, CO2 huff-n-puff operations should not have more than five cycles. NMR T2 spectrum analysis shows that in the first cycle, the oil in macro and medium pores (>50 ms) is produced first, followed by small pores (10–50 ms), accounting for 49.5%–79% and 8%–37% of the total ORF, respectively, whereas, oil from the micropores (<10 ms) is rarely produced. However, for the subsequent cycles, the oil production in macro pores and medium pores decreases while that in small pores and micropores increases. Thus, the small pores and micropores become the main oil producing areas.

Long Short-Term Memory and Variational Autoencoder With Convolutional Neural Networks for Generating NMR T2 Distributions

Downhole nuclear magnetic resonance (NMR) logs acquired in the borehole environment are valuable for subsurface characterization because they contain information about the pore size distribution, fluid composition, fluid saturation, fluid mobility, formation permeability, and porosity. NMR log acquisition can be challenging due to operational and financial constraints. Recently, NMR T2 distributions of the subsurface were generated by processing conventional well logs using deeplearning neural-network (NN) models. This improves the accessibility to subsurface pore size distributions. We implement two neural-network models, variational autoencoder-based NN with convolutional layers and long short-term memory (LSTM), to generate NMR T2 distributions from formation mineral content and fluid saturation logs. Prediction performance is evaluated for the entire NMR T2 spectrum ranging from 0.3 to 3000 ms as well as for T2 spectra within four bins obtained by dividing the entire spectrum into four equal parts. Each bin represents a specific pore size range. In terms of R <sup xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</sup> , both the models have prediction performances above R <sup xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</sup> of 0.75 for the entire spectrum. The best prediction performance is achieved for the bin of size ranging from 2.7 to 28 ms, representing pore diameters from 10 to 100 nm. The performance of this bin in terms of R <sup xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</sup> is 0.78. The LSTM model is highly sensitive to noise in T2 distribution used during the training, and both the models are robust to noise in the conventional input logs.

Characterization of pore size distributions of shale oil reservoirs: A case study from Dongying sag, Bohai Bay basin, China

Abstract Shale oil reservoirs characterized by complex pore structures typically contain a wide pore size range from nanometers to millimeters. The pore size distribution (PSD) is one of the most critical parameters affecting fluid storage and transport properties in shale oil reservoirs. Quantitatively and accurately determining PSD is of great importance for evaluating the shale oil occurrence state and movable fluid volume. In this study, four major techniques, including nitrogen adsorption (NA), scanning electron microscopy (SEM), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR), were adopted to determine pore sizes in ten shale oil reservoir samples from Dongying sag, Bohai Bay basin, China. NMR T2 spectra were converted to PSDs by using a new subsection calibration method based on the NA and SEM measurements; using the linear and power exponent conversion models, these two models are compared. The results show that the subsection calibration is an effective method for shale NMR T2 spectrum conversion. Shale oil reservoir T2 spectra can be converted to full-scale PSDs by combining NA micropore ( 1000 nm) in shale oil reservoirs; however, they are mainly connected by small-scale throats. Therefore, the comprehensive characterization of shale oil reservoir pore structures may be efficiently and accurately determined by a combination of NMR and MICP.

Insights into fractal characteristics of pores in different rank coals by nuclear magnetic resonance (NMR)

Low-field nuclear magnetic resonance (NMR), as a nondestructive and time saving method, has been widely used to evaluate the petrophysical properties of coalbed methane (CBM) reservoirs. To better understand the impacts of pore structures on permeability, NMR T2 spectrums of different rank coals and their meaning to porosity and permeability were investigated. Fractal dimensions of coal pores with NMR T2 spectrum and their correlations with porosity, Ro,m, and permeability were synthetically analyzed. The results show that T2 spectrums can be divided into three types named as unimodal, bimodal, and trimodal based on the spectrum peaks. The percentage of spectrum peak P1 increases with increasing Ro, m and the connectivity of different peaks can effectively reflect the permeability. The irreducible fluid and movable fluid porosity have an opposite relationship with increasing percentage of centrifugal fluid and increasing Ro,m. Fractal dimensions of adsorption pores (D1, 0.82–1.94) and seepage pores (D2, 2.50–2.99) demonstrate that coal pores have multiple fractals. Due to the coalification jump, both D1 and D2 show binomial relationship with Ro,m at the inflection section of 1.3–1.5% Ro,m. Generally, movable fluid porosity, irreducible fluid porosity, and total porosity show exponentially decreased or binomial relationship with the increasing D1 and D2. The development of microfractures could be the main cause of abnormal tendency between D2 and total porosity in the high-rank coals. The movable fluid porosity that reflects the proportion of seepage pores decreases with the increasing D2, which have a significant impact on low permeability coals. Most seepage pores that contributed permeability is lower than 0.1 mD, which contributes less than 20% to total permeability. However, seepage pores that contributed permeability may have an important role on CBM production, especially at the middle to late stage.

Pore Structure Evaluation of Bioclastic Limestone Using NMR and HPMI Measurements

Pore structure evaluation is a crucial segment of revealing the reservoir characteristics and percolation mechanism. Considering the diversity of origins, types and combinations in reservoir space, the effective evaluation method of bioclastic limestone pore structure had not been built yet, which greatly restricted the comprehension of storage-permeability mechanism, as well as the subsequent development strategies. Therefore, this study systematically analyzed the corresponding relationship between the fractal characteristics of capillary pressure curves and pore connectivity. The T2 relaxation criterion of different pore diameter components were determined reasonably according to the features of nuclear magnetic resonance T2 spectrum. Combined with a fuzzy clustering algorithm, a new logging classification method was established using proportions of different pore components as sensitive parameters. The results showed that the capillary force curves of bioclastic limestone reservoir mainly exhibited two kinds of form: “convex” and “concave”. The former showed better storage-percolation characteristics; while the same characteristics of the latter were closely related to inflection points, degrading by the location of respective point from right to left; In addition, the relationship between the pore throat radius r and nuclear magnetic relaxation time T2 could be classified into four stages obviously. With the pore throat radius of 0.15, 1, 5 μm and T2 relaxation time 30, 90 and 200 ms, the pore structure of bioclastic limestone was effectively divided into four categories. On this basis, the calculation precision of permeability would be significantly improved.

Micro/nanoscale pore structure and fractal characteristics of tight gas sandstone: A case study from the Yuanba area, northeast Sichuan Basin, China

Abstract The pore size distribution (PSD) and fractal dimension are two typical parameters that are used to evaluate the heterogeneous characteristics of unconventional reservoir pores. The micro/nanoscale PSD and pore fractal-dimension characteristics of tight gas sandstones from the Upper Triassic Xujiahe formation in the Yuanba area were investigated by using nuclear magnetic resonance (NMR), nuclear magnetic resonance cryoporometry (NMRC), mercury injection capillary pressure (MICP) and scanning electronic microscopy (SEM) techniques. To date, no other attempts have been made to use NMRC with octamethylcyclotetrasiloxane (OMCTS) as a probe material to describe the pore fractal characteristics of tight gas sandstones. In this study, the fractal dimensions of tight gas sandstones were estimated by processing raw NMRC data with a fractal theoretical model, and the NMRC fractal results were compared to the calculated fractals from the MICP tube model, MICP sphere model and NMR T2 spectrum. The results consistently show that the pore fractal characteristics of tight sandstone samples from the Yuanba area exhibit multiple fractal structures at different pore-size ranges; large pores in the samples are more complex with rougher surfaces, and small pores correspond to smoother surfaces. Sandstones with greater porosity and pore space possess more heterogeneous structures. The PSD and fractal dimensions can be combined and used as an indicator for the presence of gas-bearing and dry formations in the study area. The tight sandstone samples from the dry formations have both lower porosities and smoother pore surfaces with smaller fractal dimensions; these characteristics may not be beneficial for the preservation of hydrocarbon fluids in the target area.

The impacts of flow velocity on permeability and porosity of coals by core flooding and nuclear magnetic resonance: Implications for coalbed methane production

The fluid flow velocity has a significant effect on the coalbed methane (CBM) production by influencing the porosity and permeability of coals during the drainage process. In this work, the fluid velocity sensitivity experiments combined with the nuclear magnetic resonance (NMR) technology were performed to investigate the impacts of various flow velocities on permeability and porosity. The results show that the permeability of different rank coals has various characteristics with the increase of flow velocity. For low rank coals, the permeability always increases first then decreases with the increase of flow velocity. However, the permeability gradually decreases with the increase of flow velocity for medium and high rank coals. For the same rank coals, the higher initial permeability is, the more severe permeability damage is. Additionally, the porosity variation reflected by NMR T2 spectrum indicates that T2 between 10 ms and 200 ms is the main reduction space of seepage paths. The influence of flow velocity on permeability is mainly due to the blockage of fluid seepage space by coal fines. Moreover, the effects of dewatering rate on CBM production were further discussed combined with field production wells. The dropping rate of working fluid level at the single-phase water stage plays an important role on the production of coal fines and gas production, especially at the late production stage. Decreasing dewatering rate at the two-phase (water and gas) stage can improve the CBM production effectively. To improve the effect of flow velocity on petrophysical properties of CBM reservoir, the dewatering rate of CBM wells should be slow and stable. Therefore, this study could be conducive to CBM production or mining safety.