Nuclear Magnetic Resonance T2 Distribution Research Articles

Petrophysical insights into pore structure in complex carbonate reservoirs using NMR data

The study delves into pore structure attributes within the complex Eocene carbonate of an Indian offshore field, encompassing pore throat, radius and their characteristics. Nuclear Magnetic Resonance (NMR) experimental data reveals crucial insights into pore structures and fluid states. This study compares the NMR T2 distribution curve with capillary pressure data from the Mercury Injection Capillary Pressure (MICP) technique, deriving linear and nonlinear conversion coefficients to transform NMR T2 spectra into equivalent pore radius distribution. Pore radius-dependent porosity partitioning, linked to permeability and the distribution of irreducible water, is conducted utilizing NMR-derived data. Following the T2 cut-off analysis, a two-segment fractal analysis of NMR T2 distribution is also carried out. This analysis unveils associations between fractal dimensions and various petrophysical parameters, including permeability, porosity, T2LM, irreducible water saturation and R50. The NMR-derived pore radius distribution is mostly unimodal, occasionally slightly bimodal. Six different pore size classes (less than 0.05 μm to more than 5 μm) are analysed in relation to permeability, porosity and irreducible water. Small pores (<1 μm) contribute more to irreducible water with low porosity and permeability. The fractal dimension of large pores correlates strongly with porosity, permeability, T2LM, irreducible water and R50 suggesting significant impact on reservoir seepage capacity. In addition to porosity partitioning, the current study demonstrates effectiveness in modelling modified permeability and correlating it with in situ permeability when applied to field NMR log data from the study area. While numerous studies focus on sandstone, our study marks the pioneering attempt at a comprehensive analysis on complex carbonate reservoirs.

Experimental study on gas slippage effect in coal at different temperatures based on nuclear magnetic resonance

Coalbed methane (CBM) can be recovered more effectively through heat injection mining. The slippage effect in coal becomes more significant as CBM is exploited, essential for maintaining consistent production of CBM wells. By “slippage effect,” we mean that gas molecules exhibiting non–zero velocity near the wall surface of coal pores, leading to higher gas permeability than liquid permeability. To explore the slippage effect and its control mechanism during heat injection mining, methane seepage experiments with constant effective stress were conducted under five different temperatures and seven pore pressures. An analysis was conducted on the mechanisms by which pore pressure and temperature affect gas slippage effect. Furthermore, the correlation between coal pore structure and the gas slippage effect was revealed using the nuclear magnetic resonance (NMR) technique. The results appear that, first, as pore pressure increases, the slippage effect is suppressed due to the influence of the average molecular free path, despite the positive impact of adsorption–induced matrix expansion. Second, as temperature rises, the average molecular free path and thermal expansion have a positive impact on gas slippage, while matrix shrinkage caused by desorption has a negative impact. The positive impact is stronger, resulting in a continuous enhancement of the slippage effect. Finally, a new slippage factor calculation based on NMR T2 distribution of micropores and transitional pores (&amp;lt;100 nm, T2 &amp;lt; 8.33 ms) was provided, and the method was verified by slippage factor fitted by permeability experimental data. The heat injection mining of CBM can be theoretically guided by the research results.

Residual trapping of CO2, N2, and a CO2-N2 mixture in Indiana limestone using robust NMR coreflooding: Implications for CO2 geological storage

Carbon capture and sequestration (CCS) in geological formations is a prominent solution for reducing anthropogenic carbon emissions and mitigating climate change. The capillary trapping of CO2 is a primary trapping mechanism governed by the pressure difference between the wetting and nonwetting phases in a porous rock, making the latter a key input parameter for dynamic simulation models. During the CCS operational process, however, the CO2 is prone to contamination by impurities from various sources such as surfaces (e.g., pipelines and tanks) and the subsurface (e.g., existing natural gas). Such contamination can strongly influence the overall CO2 wettability, storage capacity, and containment security. Hence, the present study uses the nuclear magnetic resonance (NMR) core flooding technique to investigate and compare the residual saturations of pure CO2, pure N2, and a 50:50 CO2/N2 mixture in an Indiana limestone. The longitudinal and transverse relaxation times (T1 and T2) are measured to examine the displacement process of the pore network, and the trapping mechanism is evaluated at the pore scale as a determinant of the field-scale flow behavior. The NMR T1-T2 and 2D maps are used to observe the fluid configurations in the pore network, and the T1/T2 ratios are used to evaluate the microscopic wettability of the limestone grains by the pore-space fluids following each drainage/imbibition process step. The results indicate substantial residual gas trapping in the rock for the CO2-brine, N2-brine, and CO2/N2-brine systems, corresponding to gas saturations of 25%, 27%, and 26%, respectively. In the CO2-brine system, the intermolecular interplay between the CO2-enriched brine and limestone grains results in a higher T1/T2 ratio and significantly reduces the hydrophilicity of the limestone. Furthermore, the NMR T2 distribution reveals the occurrence of preferential water displacement into the large pores (r > 1 µm) and from the intermediate pores (0.03 µm < r < 1 µm), whereas water remains immobile in the smaller pores (r < 0.03 µm). The insignificant difference in residual trapping saturation between pure CO2 and the CO2-N2 mixture indicates the potential to allow for impurities in the CO2 phase in CCS without reducing the residual trapping capacity. Thus, the present work provides comprehensive information on the impact of gas injection on residual gas trapping in subsurface geological formations at the pore scale, thereby aiding in the development of CCS and other potential applications in enhanced oil recovery (EOR).

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-Mapped Distributions of Dielectric Dispersion

Combinations of NMR and dielectric measurements frequently address challenging saturation and wettability determinations in conventional reservoirs. When pore structure effects are addressed, the nuclear magnetic resonance (NMR) characteristics are interpreted based on the evaluations of surface relaxivity, and the dielectric structural response is attributed to the “texture” of the rock matrix. Both pore structure descriptors can be improved if the molecular motions and charge mobility common to the measurements are considered. Similar to the dipolar relaxation equivalence of NMR and dielectric correlation time measurements in the Bloembergen, Purcell, and Pound (BPP) model, we develop a relaxation time correlation assuming representative Maxwell-Wagner relaxations. Dielectric dispersion curves for the carbonate matrix and vug pore components demonstrated by Myers are quantified using a dielectric relaxation time (DRT) model. The modeled pore system fractions are spectrally mapped to the NMR T1 or T2 distributions based on enhanced Debye shielding distances correlated with the conductivity. The characterized NMR distributions are validated with micro-CT pore-size determinations and diffusion correlations. The mapped distributions provide petrophysical insight into the frequently used Archie exponent combination (mn) associated with conductivity tortuosity and additional wettability screening criteria.

Pore structure characterization based on NMR experiment: A case from the Shanxi Formation tight sandstones in the Daning-Jixian area, eastern Ordos Basin

The study of pore structure requires consideration of important factors including pore throat size, pore radius composition, and pore-throat configuration. As the nuclear magnetic resonance (NMR) experimental results contain rich information about pore structures and fluid occurrence states, this study investigated the pore structures of the tight sandstone reservoirs of the Shanxi Formation in the Daning-Jixian area, eastern Ordos Basin. Firstly, by making the inverse cumulative curve of the NMR T2 spectrum coincide with the capillary pressure curves which were obtained by the mercury injection capillary pressure (MICP) technique, this study derived a conversion coefficient that can be used to convert the NMR T2 spectrum into the pore throat radius distribution curves based on the NMR experimental results. Subsequently, we determined the pore radius intervals corresponding to irreducible water distribution using the NMR-derived pore radius distribution curves. Finally, the NMR T2 distribution curves based on the fractal theory were analyzed and the relationships between fractal dimensions and parameters, including permeability, porosity, reservoir quality index (RQI), flow zone indicator (FZI), irreducible water saturation, RT35, and RT50, were also discussed. The NMR-derived pore throat radius distribution curves of the study area are mainly unimodal, with some curves showing slightly bimodal distributions. The irreducible water mainly occurs in small pores with a pore radius less than 100 nm. As the permeability decreases, the contribution rate of small pores to the irreducible water gradually increases. The NMR-based fractal dimensions of pores show a two-segment distribution. Small pores have small fractal dimensions and are evenly distributed, while large pores have large fractal dimensions and complex pore structures. The fractal dimension of large pores (Dmax) is poorly correlated with porosity but strongly correlated with FZI, RQI, RT35, and RT50. These results indicate that large pores are the main pore zones that determine the seepage capacity of the reservoirs. Additionally, there is a certain correlation between Dmax and the irreducible water saturation.

A novel approach for estimating pore size distribution and capillary pressure in hydrocarbon zone through hydraulic flow unit framework using NMR log

Nuclear magnetic resonance (NMR) logging imparts a wealth of information regarding the petrophysical characterization of rocks including pore size distribution and capillary pressure. However, the NMR data can only be comprehensively utilized when formation pores are fully water-saturated. As with hydrocarbon saturation increase in rock pores the NMR's transverse relaxation curve (T2 distribution) gets distorted and this in turn causes flawed measurement of petrophysical and fluid properties. Therefore, the estimation of representative pore structure and capillary pressure from hydrocarbon zone utilizing T2 distribution has traditionally been quite arduous. The previous correction methods in this regard mostly require expensive core data for their implementation, which makes them less desirable. In this study, a novel workflow has been introduced which does not necessitate expensive core data for its application. The new method employs the concept of hydraulic flow units (HFUs), which are zones within a reservoir having consistent petrophysical and geological properties to subdivide the reservoir rock while investigating the T2 distribution character variation through a statistical approach to determine the most optimally informed reconstruction of effected T2 distributions in hydrocarbon zone for accurate petrophysical characterization. After implementing the novel workflow on a carbonate reservoir having gas, the before and after comparative analysis of T2 distribution, pore size distribution (PSD) and capillary pressure curves show promising results. The novel workflow establishes a robust and cost-effective methodology for NMR T2 distribution correction in hydrocarbon zone for un-cored and partially cored wells.

Application of Multifractal Analysis Theory to Interpret T2 Cutoffs of NMR Logging Data: A Case Study of Coarse Clastic Rock Reservoirs in Southwestern Bozhong Sag, China

The Paleocene Kongdian Formation coarse clastic rock reservoir in Bozhong Sag is rich in oil and gas resources and has huge exploration potential. However, the coarse clastic rock reservoir has the characteristics of a complex pore structure and strong heterogeneity, which restrict the accuracy of evaluating the reservoir’s physical properties, such as porosity and permeability, for field evaluation. Nuclear magnetic resonance (NMR) technology has become a popular methods for unconventional reservoir evaluation because it can obtain abundant reservoir physical property information and because of its ability to identify fluid characteristics information. The transverse relaxation time (T2) cutoff (T2C) value is an important input parameter in the application of NMR technology. The accuracy of the T2C value affects the accuracy of the reservoir evaluation. The standard method for determining the T2C value requires a series of complicated centrifugation experiments in addition to the NMR experiments, and its application scope is limited by obtaining enough core samples. In this study, 14 core samples from the coarse clastic rock reservoir in the southwestern Bozhong sag of the Bohai Bay Basin were selected, and NMR measurements were carried out under the conditions of fully saturated water and irreducible water to determine the T2C value. Based on the multifractal theory, the NMR T2 spectrum of the saturated sample was analyzed, and the results show that the NMR T2 distribution of the saturated sample has multifractal characteristics, and the multifractal parameter Dq and the singular intensity range Δα have a strong correlation with the T2C value. Thus, based on multiple regression analyses of the multifractal parameters with the experimental T2C value of 10 core samples, we propose a method to predict the T2C value. After applying this method to 4 samples that were not used in the modeling, we confirmed that this method can be used to predict the T2C value of core samples. Furthermore, we expanded this method to the field application of a production well in Bozhong sag by adding an empirical index in the model. The new model can be used to directly calculate the T2C value of NMR logging data, and it does not require any other extra data, such as those from core analysis. This method is applicable in fast reservoir evaluations by only using NMR logging data in the field. The research results improve the accuracy of field NMR logging reservoir evaluations.

Quantitative Investigation on Natural Gas Flooding Characteristics in Tight Oil Cores after Fracturing Based on Nuclear Magnetic Resonance Technique

SummaryTight reservoirs are mainly developed by injecting various gases after fracturing. However, the formed fractures are complex, and different fracture conditions have an important impact on the gas injection effect. In addition, natural gas is considered to be suitable for the development of tight reservoirs in China because of the abundant gas source and no corrosion. For this paper, the natural gas injection experiments were studied by combining mercury intrusion porosimetry (MIP) measurements and nuclear magnetic resonance (NMR) measurements. The method can be used to study the distribution characteristics of core pore structure and the recovery characteristics of oil in different pore spaces.In this work, the tight cores of the Changqing Oil Field were selected for fracturing for the natural gas flooding experiments. At first, the distribution characteristics of the core pore structure were studied based on the MIP and NMR measurements. The conversion relationship between the core pore throat radius and the relaxation time (T2) was decided. The NMR T2 distribution was transformed into the distribution of oil in pore space with different throat radii. Then, the gasflooding experiments were conducted to study the oil recovery law of tight cores with different fracture conditions. Finally, the recovery characteristics of oil in different pore spaces were analyzed based on the NMR results of cores.The results show that the pore throat radius of the core is mainly distributed in the range of 0.001 to 10 μm. The oil is mainly stored in the pore space whose pore throat radius ranges from 0.01 to 1 μm. The natural gas also mainly drives the saturated oil in the pore space with a pore throat radius of 0.01 to 1 μm. The increase in fracture area improves the distribution of oil in the larger pore space. In the process of natural gasflooding, with the increase of gas injection, the oil began to be recovered, and then gas was observed at the end of the core. With the continuous injection of natural gas, the rate of recovering oil gradually slowed down, and finally gas breakthrough occurred. The displacement oil process of the nonfractured core was uniform and slow. However, the oil and gas rapidly flowed along the fracture when the natural gas displaced the oil in the fractured core. The oil in the matrix was poorly recovered. Gasflooding mainly recovered the saturated oil in the matrix of nonfractured cores and the saturated oil in the fracture of fractured cores. As the fracture length increased, the oil recovery became lower and the gas breakthrough occurred earlier. The higher fracture density increased the fracture area, which also increased the oil recovery and caused a more intense gas breakthrough.In this paper, the displacement law of tight oil cores by injecting natural gas and the recovery characteristics of oil in different space pores were illuminated. The results can provide theoretical guidance for the formulation of the natural gas injection development plan in tight reservoirs.

Classification of Tight Sandstone Reservoirs Based on the Nuclear Magnetic Resonance T2 Distribution: A Case Study on the Shaximiao Formation in Central Sichuan, China

The classification of tight sandstone reservoirs is of significance for hydrocarbon exploration and production. Different from conventional reservoirs, tight sandstone reservoirs are characterized by a complex pore structure and strong heterogeneity. Tight sandstone reservoir classification may not be reliable with conventional reservoir classification methods. In this paper, a classification method of tight sandstone reservoirs was proposed on the basis of the nuclear magnetic resonance (NMR) transverse relaxation (T2) distribution, and it was employed for reservoir classification on the Shaximiao Formation in central Sichuan, China. As a result of the complex pore structure of a tight sandstone reservoir, the NMR T2 distribution is characterized by the presence of multiple peaks. Therefore, the three-peak Gaussian function was used to fit the T2 distribution and obtain the characteristic parameters. On the basis of high-pressure mercury intrusion (HPMI) experiments, the correlation between the characteristic parameters of the NMR T2 distribution and pore structure parameters and petrophysical properties was analyzed, and then the optimal characteristic parameters of the NMR T2 distribution were selected according to the results of correlation analysis and used to establish the pore structure index. In combination of petrophysical properties with the pore structure index, the model for classification of tight sandstone reservoirs was established by the naive Bayesian method based on hierarchical clustering, and the accuracy of the model was verified by k-fold cross-validation. Finally, the effectiveness of the proposed method was verified using the actual NMR logging data in conjunction with the oil test data. The results showed that the method for classification of tight sandstone reservoirs based on the NMR T2 distribution can provide effective guidance for production capacity evaluation.

Fractal-based NMR permeability estimation in tight sandstone: A case study of the Jurassic rocks in the Sichuan Basin, China

Permeability is a crucial parameter evaluating tight sandstone reservoir. Previous permeability estimation methods based on nuclear magnetic resonance (NMR) are commonly suitable for well-sorted, highly porous and unconsolidated sandstone, but incurring large errors when applied to tight sandstone. This study introduces the fractal dimension based NMR permeability estimation for tight sandstone. Core permeability and NMR measurements were performed on thirty tight sandstone samples selected from the Jurassic rocks in the Sichuan Basin, China. We proposed two fractal-based NMR permeability models for tight sandstone in the studying area, which are considered as the modifications of the SDR and T-C models, examining the applications on core plug samples and comparing the results with other permeability models. Results show that tight sandstones have wider T2 distribution and weaker correlation between throat size and pore size than unconsolidated/clean sandstones. The proposed coefficient-based optimal fitting method can obtain more accurate fractal dimensions of micropores and macropores than these achieved by subjective and empirical methods and commonly used T2cutoff method. The proposed models introduced in this research have two advantages: (1) the models have high accuracy since the effective pore structure parameters (porosity, FFI/BVI and T2LM) are adopted. The complex pore structure of tight sandstones is considered by using fractal dimensions. (2) the models are easy to implement by following the concise formats of the Timur-Coates model and SDR model. In practice, the models can be applied to predict permeability of tight sandstone in the lab, or in the field requiring NMR T2 distributions as basic data, integrating core permeability to determine fitting parameters in the models.

Learnings From a New Slimhole LWD NMR Technology

This paper presents recent results obtained from a new 4.75-in. logging-while-drilling (LWD) nuclear magnetic resonance (NMR) tool. Data from several wells provided real-time operational insight and new petrophysical learnings. The new LWD technology offers an innovative capability to simultaneously measure NMR T1 and T2 distributions with reduced sensitivity to drilling mud conductivity and a real-time sensor motion-warning system. The real-time T1 and T2 spectra compare favorably with the data set retrieved from the tool memory. The LWD NMR measurements were followed by wireline (WL) NMR logging for comparison in three wells. In carbonate reservoirs, the main objective was to evaluate the new NMR tool’s capability in resolving carbonate pore size with slow NMR relaxation rates. Another set of NMR logs contained time-lapse repeat passes in a well drilled with oil-based mud (OBM) that traversed a clastic reservoir. The sequence of measurements identified rock types and provided a unique insight into the mud filtrate invasion process. In a carbonate reservoir, the LWD NMR real-time partial porosity estimates were in excellent agreement with the core-calibrated WL micro-, meso-, and macropore volumes. Another carbonate formation contained high-permeability layers embedded in a microporous rock, where the real-time LWD NMR logs successfully located the high-quality rock zones, later verified by WL logging. In the clastic reservoir, the while-drilling LWD NMR data indicated native light hydrocarbons, whereas the subsequent LWD reaming and WL NMR passes showed a displacement of native hydrocarbons by oil-based mud filtrate (OBMF). The native hydrocarbon signature observed by the LWD NMR tool was in good agreement with the mud gas log. OBMF invasion occurred shortly after drilling, indicated by the differences observed in the LWD NMR relogged data acquired several hours after the while-drilling pass. The WL NMR data, logged about 4 days after drilling, showed advanced stages of OBMF invasion, including formation water displacement and wettability changes in intermediate and large pores. Finally, the environmental noise remained low in the LWD NMR data set acquired in a well in which the mud salinity changed by several folds, indicating that mud salinity had little effect on the quality of LWD NMR logs in slim holes. The new slimhole LWD NMR technology demonstrated its robust capability to provide T1 and T2 logs through several examples. For the first time, a time-lapse comparison of NMR logs showed that OBMF invasion could occur in silty sands with high capillary-bound fluid fractions.

Fluid substitution in NMR T2 distribution and resistivity independent saturation computation using synthetic capillary pressure data

Petrophysicists and reservoir engineers utilise the capillary pressure and saturation-height function for calculating the water saturation of any reservoir, at a given height above the free water level. The results have a big impact on reserve estimation. The majority of capillary pressure studies are carried out in labs with core data. Cores, on the other hand, are usually altered from their original state before being delivered to laboratories. Moreover, the accuracy of discrete sets of core data in describing entire reservoir parameters, is still up for debate. Prediction of the capillary pressure curve in reservoir condition is an important subject that is challenging to perform. The use of nuclear magnetic resonance (NMR) logs for oil and gas exploration has grown in popularity over the last few decades. However, most of the time the utilization of the data is limited for evaluating porosity-permeability, distributions and computation of irreducible water saturation. After the advent of fluid substitution methods, NMR T2 distributions may now be used to synthesize core equivalent capillary pressure curves. Using fluid substitution workflow, our study introduces a better approach for obtaining capillary pressure curves from the NMR T2 distribution. The available core data has been used to calculate calibration parameters for better saturation height modelling. The workflow introduces a novel approach in resistivity independent saturation computation. In the exploratory wells of our study area, computed water saturation derived from the saturation height function exhibits encouraging agreement with resistivity based water saturation from multi-mineral model. The NMR based saturation height modelling approach has been included in study area for the first time so far.

A modified nuclear magnetic model for characterizing the fluid signal response in hydrocarbon bearing rocks

The nuclear magnetic resonance (NMR) technique is a crucial means for formation evaluation. It can provide an accurate set of formation parameters in single-phase-flow reservoirs, such as porosity, permeability, and pore structure distribution; however, in most cases, there are hydrocarbon-water two-phase fluids in the reservoirs. The secondary change of the T2 distribution makes the accuracy of the evaluation a challenge. Hence, it is necessary to clarify the impact of changes in hydrocarbon content on the response of NMR signals before using the traditional evaluation methods. In this paper, we analyzed the response mechanism of NMR T2 distribution under different saturation conditions. Based on the theoretical derivation, we established a nuclear magnetic model that describes the relation among the T2 geometric mean value of water signal, hydrocarbon signal, and water saturation. The accuracy of each model part was verified by numerical simulation. In addition, the calculation results in core samples show that the proposed model is more effective and reliable than two existing models (the T2 saturation ratio model and the Xiao empirical model), especially in extreme conditions (irreducible water and hydrocarbon saturated samples). Finally, we applied the proposed model to field application in the Tertiary formation in the Bohai Bay Basin, China, which achieved good effects in the NMR fluid substitution and the NMR saturation evaluation.

Pore-fracture network alteration during forced and spontaneous imbibition processes in shale formation

Imbibition controls mass transfer in the complex pore-fracture network in shale, which may change the pore-fracture network and lead to a low efficient flowback of fracturing fluid. Thus, it is necessary to accurately characterize the pore-fracture network alteration during the imbibition process. In this study, forced and spontaneous imbibition tests were conducted under the confining pressure on selected shale core samples with induced fractures, collected from Longmaxi Formation, Sichuan Basin, China. The low-field nuclear magnetic resonance (NMR) spectrometer was employed to monitor the variation of pores and micro-fractures in the shale core samples during the dynamic imbibition process. In addition, optimal surface relaxivities, ranging from 0.019 to 0.033 μm/ms, were determined by comparing the NMR T2 distributions with the pore size distributions (PSDs) measured via high-pressure mercury intrusion (HPMI) tests. Then, the measured dynamic T2 spectra with three distinct peaks were converted into the corresponding PSDs to quantitatively analyze the number, size, and connectivity changes of small pores, large pores, and micro-fractures in shale. Results show that the total porosities of the four shale core samples are increased by 3.5%, 10.2%, 32.9%, and 36.3% after the imbibition tests. The forced imbibition leads to more remarkable improvements in the pore volume of large pores with radius between 0.2 and 3.6 μm. In contrast, the spontaneous imbibition results in more significant increases in the number and size of small pores with radius between 0.0004 and 0.36 μm. It is also found that the total porosity increment is primarily an outcome of small pore alteration during the imbibition. Moreover, the enlarged pores and micro-fractures are mainly categorized as the capillary bounded fluid pores and movable fluid pores, which significantly affect the efficiency of oil and gas transfer in shale. The findings of our study demonstrate the comprehensive effects of capillary force, clay hydration, osmotic potential, confining and pore pressures, and creep deformation and failure on the pore-fracture network alteration in shale and advance the understanding of the mechanisms behind the forced and spontaneous imbibition processes.

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.

Machine learning in the classification of lithology using downhole NMR data of the NGHP-02 expedition in the Krishna-Godavari offshore Basin, India

We apply machine learning techniques to classify the lithology using downhole nuclear magnetic resonance (NMR) data of gas hydrate reservoirs in the Krishna-Godavari (KG) Basin, eastern Indian offshore. We choose two sites of the second expedition of the Indian National Gas Hydrate Program (NGHP-02) for our study, one with clay dominated site NGHP-02-01 from Area E and another with silt/sand dominated site NGHP-02-05 from Area C. We obtain five distinct classes in NMR signals at two sites using unsupervised techniques such as Davies-Bouldin index, silhouette, self-organizing map, k-means clustering and emergent self-organizing map. Obtained classes are interpreted using the NMR T2 distribution pattern with time in terms of clay, silt, sand and pebble/gravels with depth and reconciled with gamma-ray, density, porosity, resistivity, velocity and photoelectric factor. Our results demonstrate the lithology as silty-clay with minor sand at Hole NGHP-02-01A, and silt, sand with less clay and minor pebble/gravel at Hole NGHP-02-05A. The presence of gas hydrate is identified by observing an overall low amplitude T2 distribution curve, which is due to the reduction of pore space by solid gas hydrate. The maximum concentration of gas hydrate of about 43% of pore space estimated using NMR- and density-porosity are distributed mainly in silty-clay at Hole 01A and of about 75% in clayey-silt and silty-sand at Hole 05A. Low amplitude NMR T2 signals observed in clay-dominated sediments at higher relaxation time may be due to the fracture-filled gas hydrates at both holes. Interestingly, high porosity (90–95%), high permeability (4 mD), low bulk-density (1.2 gm/cm3) and low photoelectric factor (0.8 b/electron) are found in sandy layers within the gas hydrate-stability zone at Hole 05A, which possibly comprising buried channels. Comparison of the lithology obtained from other log data with that from NMR data and core samples illustrates that the NMR data are most effective for characterization of reservoirs, except for a high concentration of gas hydrate in a sandy/coarse-grained reservoir, which needs further studies.

CO2 – brine – sandstone wettability evaluation at reservoir conditions via Nuclear Magnetic Resonance measurements

CO2-rock wettability is a key parameter which governs CO2 trapping capacities and containment security in the context of CO2 geo-sequestration schemes. However, significant uncertainties still exist in terms of predicting CO2 rock wettability at true reservoir conditions. This study thus reports on wettability measurements via independent Nuclear Magnetic Resonance (NMR) experiments on sandstone (CO2–brine systems) to quantify Wettability Indices (WI) using the United States Bureau of Mines (USBM) scale. The results show that CO2 (either molecularly dissolved or as a separate supercritical phase) significantly reduced the hydrophilicity of the sandstone from strongly water-wet (WI ≈ 1) to weakly water-wet (WI = 0.26), and associated with that the water-wetness of the rock for the two-phase systems. This was caused by additional protonation of surface silanol groups on the quartz, induced by carbonic acid. Capillary pressure and relative permeability curves and residual CO2 saturation were also measured; these results were compared with literature data, and general consistency was found. NMR T2 distribution measurements also demonstrated preferential water displacement in large pores (r > 1 µm) following scCO2 flooding, while no change was observed for smaller pores (r < 1 µm). These insights add confidence to the assessments of CO2-rock wettability and therefore reduce project risk. This work thus aids in the implementation of large-scale CO2 sequestration.

NMR Fluid Substitution–A New Method of Reconstructing T2 Distributions Under Primary Drainage and Imbibition Conditions

Most nuclear magnetic resonance (NMR)-based petrophysics models, such as pore structure characterization and permeability prediction, were developed using T2 distributions measured at fully water-saturated conditions (i.e., Sw = 1). The downhole implementation of those models across the hydrocarbon zones is disputable due to partial saturation (Sw &lt; 1) conditions; hence, a correction to such effects on T2 distributions is required. This paper provides a critical review of the fluid substitution methods currently available in the industry and presents an improved method for enhanced formation evaluation. In the new method presented, an effective irreducible water saturation model is used to account for the pore structure and capillary pressure effects, which were barely considered by the currently available NMR fluid substitution methods. For water-wet reservoir rocks, the typical NMR T2 distribution at the partial saturation condition displays a clear separation between the wetting and nonwetting phases. The water phase can be classified as irreducible and movable fluid volumes. Then, using a T2 mapping relationship and a total porosity constraint, the T2 distribution of movable water at Sw &lt; 1 is shifted and amplified to determine the T2 distribution of movable water at Sw = 1. To validate the new method, NMR measurements were conducted on sandstone samples at Sw = 1 as well as Sw &lt; 1. The reconstructed T2 distribution at Sw = 1 was compared with the measured T2 distribution at Sw = 1. Results showed that the reconstructed T2 distribution matched very well with the T2 distribution measured at Sw = 1, confirming the robustness of the new technique. Parameters used in the reconstruction methodology are observed to be a good indicator of pore connectivity. During desaturation, the water T2 in large pores shifts to a shorter T2 because of the enhanced surface relaxation as the water volume decreases while the surface area remains constant. Therefore, the amplitude at the short T2 increases. The increased amplitude was remapped to large pores in reconstructing T2 spectra of full saturation.

Spontaneous imbibition characteristics of carbon nanofluids in carbonate reservoirs

Altering the wettability of the rock–oil–brine system plays a substantial role in the oil recovery process from carbonate reservoirs. Hence, there arises a need for understanding the wetting and wettability alteration of this system. In this study, we ran a suite of spontaneous imbibition tests and investigated the efficiency of Carbon nanodots (CND) and an in-house cationic Gemini surfactant (GS8) on the wettability alteration of and recovery from oil-wet carbonate rock samples. The study considered the effects of additives concentrations, sample aging, initial water saturation, and rock permeability. Both CND and GS8 proved efficient at concentrations below 200 ppm. At 200 ppm, separately CND in seawater and GS8 in seawater demonstrated each about 22%–25% incremental oil recovery over neat seawater. Low field nuclear magnetic resonance (NMR) measurements supported this observation. NMR T2 distribution and NMR T2D fluid typing measurements helped evaluate the recovery in terms of the pore size distribution and the oil and brine water saturation at different imbibition stages. CND exhibited a strong positive effect on the wettability of all tested samples, and accordingly, on the imbibition characteristics and oil recovery. It altered the wettability from strongly oil-wet to water-wet with equal efficiency in all pore systems making it a strong candidate for enhanced oil recovery (EOR). GS8, on the other hand, was most efficient in the macropores. Unlike CND, the efficiency of GS8 decreased in the mesopores and more so in the micropores. Rock–oil–brine surface contact angle and oil–brine interfacial tension measurements supported the imbibition test results and helped interpret the recovery mechanism. Overall, CND proved effective for EOR in the harsh carbonate reservoir environment and demonstrated itself as a viable and economical substitute to the more costly and complex oilfield chemicals for recovery operations.