Berea Sandstone Research Articles

Investigating the impact of pulsed plasma-based shockwave technology on the characteristics of Indian crude oil

The declining production from oil wells has become a growing concern worldwide, primarily because conventional methods are becoming less efficient in extracting the original oil reserves. Due to limitations associated with traditional oil recovery techniques, including their high expenses, depth limitations, heat losses, instability of additives, and environmental hazards, it is imperative to investigate the impact of alternative technologies on reservoir fluid properties and recovery. This research proposes a pulse plasma-based shockwave technology (PPBSW) using an indigenously developed tool that uses repeated electrohydraulic shock waves. The liquid pulsed discharge's plasma channel rapidly expands causing an electrohydraulic shock wave. The crude oil samples were exposed using repeated, steep-fronted shock waves of high strength. Crude oil samples were obtained from the Indian Oilfield and underwent characterization both before and after exposure to shockwaves. After the shockwave treatment, there were observable changes in the weight percentages of wax, saturates, aromatics, resins, and asphaltenes in the composition of the oil. C13 NMR investigations reveals that MCL (mean chain length) of the exposed samples was slightly affected. Further, the impact of shock wave on the viscosity of the crude oil was evaluated and viscosity of the samples found to be altered after exposure. Oil recovery was evaluated using core flooding studies on a saturated Berea sandstone core. The core was saturated using core plug saturator at 1000 psi. As a result of altered viscosity and reduced interactions between the rock and fluid, the oil recovery from the treated samples was approximately 24% greater as compared to the untreated samples. Given the oil recovery and mixed effect on the viscosity of studied crude oil samples, it can be inferred that PPBSW has a favourable effect on the hydrocarbon recovery.

Wettability Alteration of Berea Sandstone for Gas Condensate Applications.

Gas condensate reservoirs can suffer significant decreases in production due to the buildup of liquid in the vicinity of the wellbore, which occurs when the bottom-hole flowing pressure drops below the dew point pressure. Consequently, the generated liquid hydrocarbons can hinder the movement of the produced gas by adhering to the surfaces, thereby creating a condensate bank. One potential method for mitigating the issue of condensate banking involves the injection of chemical treatment and the alteration of wettability from a liquid-wet state to an intermediate gas-wet state. This study conducted an experimental investigation of the impact of fluorochemical treatment on altering the wettability from liquid-wetting to intermediate gas-wetting. The wettability of the Berea sandstone was analyzed before and after chemical treatment over a temperature range of 25-83 °C. The outcrop core samples of Berea sandstone used in this investigation exhibited an average porosity and permeability of 20% and 100 mD, respectively. The experimental results indicate that the application of chemical treatment has the potential to alter the wettability of Berea sandstone, transitioning it from a state of liquid-wetting to gas-wetting at standard temperatures. The chemical treatment alters the wettability from liquid-wet to intermediate gas-wet at higher temperatures. Furthermore, the alteration of wettability substantially improves the mobility of the oil phase and decreases the residual saturation of the oil, thereby aiding the reduction of liquid accumulation around the wellbore. According to this research, altering the wettability of the rock surrounding the wellbore in gas condensate reservoirs from a state of strong liquid-wet to gas-wet has the potential to enhance the deliverability of gas wells and improve injectivity in the field.

Nuclear magnetic resonance and molecular simulation study of H2 and CH4 adsorption onto shale and sandstone for hydrogen geological storage

Understanding pure H2 and H2/CH4 adsorption and diffusion in earth materials is one vital step toward a successful and safe H2 storage in depleted gas reservoirs. Despite recent research efforts such understanding is far from complete. In this work we first use Nuclear Magnetic Resonance (NMR) experiments to study the NMR response of injected H2 into Duvernay shale and Berea sandstone samples, representing materials in confining and storage zones. Then we use molecular simulations to investigate H2/CH4 competitive adsorption and diffusion in kerogen, a common component of shale. Our results indicate that in shale there are two H2 populations, i.e., free H2 and adsorbed H2, that yield very distinct NMR responses. However, only free gas presents in sandstone that yields a H2 NMR response similar to that of bulk H2. About 10 % of injected H2 can be lost due to adsorption/desorption hysteresis in shale, and no H2 loss (no hysteresis) is observed in sandstone. Our molecular simulation results support our NMR results that there are two H2 populations in nanoporous materials (kerogen). The simulation results also indicate that CH4 outcompetes H2 in adsorption onto kerogen, due to stronger CH4-kerogen interactions than H2-kerogen interactions. Nevertheless, in a depleted gas reservoir with low CH4 gas pressure, about ∼30 % of residual CH4 can be desorbed upon H2 injection. The simulation results also predict that H2 diffusion in porous kerogen is about one order of magnitude higher than that of CH4 and CO2. This work provides an understanding of H2/CH4 behaviors in deleted gas reservoirs upon H2 injection and predictions of H2 loss and CH4 desorption in H2 storage.

Extracting crucial microstructures to characterize the elastic wave velocity and resistivity of Berea sandstone using convolutional neural networks

To reveal the internal structure of the earth, rock physical models are insightful for interpreting geophysical observation data and are often used for estimating subsurface structures. However, as the estimated value of each model significantly depends on the assumed microstructure, the obtained subsurface structure may be biased. Despite the innovations of high-resolution imaging technologies and their application to digital rock physics (DRP) and machine learning (ML), the characteristic microstructure controlling rock physical properties remains unclear. We apply ML and extraction of regression activation mapping (RAM) and learned filters to visualize the characteristic microstructure underlying the elastic and electrical properties of rock (P-wave velocity [Formula: see text], S-wave velocity [Formula: see text], [Formula: see text]/[Formula: see text] ratio, and electrical resistivity). This regression task is implemented using convolutional neural networks (CNNs) that are trained on these properties and calculated with the DRP approach using Berea sandstone images as samples. Although the calculated geophysical properties show perturbations even among digital rocks that have the same porosity, the results predicted using the best-performing CNN model exhibit a relative error of 2%–7% with respect to elastic properties. The visualized RAM revealed that the machine focuses on larger grains for predicting P-wave and S-wave velocities, whereas their ratio ([Formula: see text]/[Formula: see text]) takes into account the pore space. In contrast, electrical properties consider grain edges and surrounding pores, which may be related to the tortuosity of the pore space. Moreover, filter visualizations demonstrated that the geometric characteristics of Berea sandstone could be representative of circular or elliptical shapes for determining elastic properties, whereas tube-like shapes were extracted for electrical resistivity. These findings shed new light on the crucial internal structures used for defining each rock property.

The effect of temperature on the mechanical behavior of Berea sandstone under confining pressure: experiments

For the first time, axial and circumferential (diametral) strains are measured directly on Berea sandstone cylindrical samples at different high temperatures as a function of confining pressure. The maximum compressive principal stress was in the direction perpendicular to the bedding plane. Tri-axial compression tests have been conducted under confining pressures ranging from atmospheric pressure to 12,000 psi “82.73 MPa” (gage), and the temperature was varied from room temperature (RT) to 250°F (121.11 °C). In all the experiments, specimens are dry, and no pore pressure is applied. Uniaxial axial force (100 lbs/min or 444.82 N/min) and strains in the three directions (varepsilon1, varepsilon2, varepsilon3) is directly measured from the strain gages mounted on the specimen; hence the study reflects the behavior of the Berea sandstone up to the initiation of the failure only. The experimental observations involving yield, failure, transition from brittle to ductile behavior, and their dependence on temperature and confining pressure are presented. Parameters like ductility and dilatancy (reflecting volumetric behavior before failure) and their variation with temperature and confining pressure are given. The initial yield and failure of Berea sandstone are presented in terms of the generalized von-Mises criteria, i.e., variation of octahedral shear stress () with the mean stress. The loads at yield and failure are found to decrease with increasing temperature and augment with increasing confining pressure. The ductility and dilatancy reduction are computed using measured strains with increasing temperature. With an increase in temperature, the volume decreases first, partly due to the initial closure of micro cracks and voids, then increases due to generation of additional microcracks and voids (damage). There is less volume decrease in the uniaxial test response at higher temperature as compared to the corresponding ambient temperature response. A monotonic increase in the octahedral shear stress at yield and failure is observed with increasing confining pressure.

The Effect of Multiple Cycles of Surfactant-Alternating-Gas Process on Foam Transient Flow and Propagation in a Homogeneous Sandstone

Summary Years of laboratory studies and field tests show that there is still uncertainty about the ability of foam to propagate deep into a reservoir. Many factors have been identified as potential causes of nonpropagation, the most concerning being the lack of sufficient pressure gradient required to propagate foam at locations far from the point of injection. Most researchers that investigated foam propagation did so by coinjecting surfactant and gas. Coinjection offers limited information about transient foam processes due to limitations in the experimental methods needed to measure foam dynamics during transient flow. Foam injection by surfactant-alternating-gas (SAG) has proven to be more effective and common in field application. Repeated drainage and imbibition cycle offer a more favorable condition for the quick generation of foam. Foam can also be propagated at a lower pressure gradient in SAG mode. The objective of this study is to experimentally investigate how transient foam dynamics (trapping, mobilization, and bubble texture) change with multiple cycles of SAG and also with distance from the point of injection. A pair of X-ray source and receiver, differential pressure transducers, and electrical resistance sensors were placed along a 27-cm long, homogeneous, and high-permeability (KL = 70 md) Berea sandstone core. Foam was then generated in situ by SAG injection and allowed to propagate through the core sample under a capillary displacement by brine (brine injection rate = 0.5 cm3/min, Nca = 3×10-7). By use of a novel analytical method on coreflood data obtained from axial pressure and saturation sensors, we obtained trapped foam saturation, in-situ foam flow rates, apparent viscosities, and inferred qualitative foam texture at different core sections. We then observed the following: (i) Maximum trapped foam is uniform across the core sections, with saturation ranging from 47% to 52%. At the vicinity of foam injection, foam apparent viscosity is dominantly caused by gas trapping. At locations farther away, foam apparent viscosity is dominated by both gas trapping and refinement of foam texture. (ii) Cyclic injection of foam further enhances the refinement of foam texture. (iii) Textural refinement increases foam apparent viscosity as it propagates away from the point of injection. (iv) As the foam strength increases, the average gas flow rate in the core sample decreases from 0.5 cm3/min to 0.06 cm3/min. (v) There is no stagnation of foam as remobilization of trapped gas occurs during each cycle at an average flow rate of 0.002 cm3/min.

Effect of rock surface wettability on hydrogen-cushion gas adsorption with application to hydrogen storage in depleted oil and gas reservoirs

In this study, adsorption capacity of Berea sandstones varying wettability states with respect to hydrogen (H2) and hydrogen-methane (H2-CH4) mixture are examined to assess the viability of depleted oil and gas reservoirs for large scale hydrogen storage. We investigate pure hydrogen and hydrogen-methane mixture adsorptions as a function of pressure, temperature, and rock surface wettability. The obtained results indicate that as the CH4 fraction increases from 0 to 20 %, the gas uptake exhibits a more significant rise, going from 0.98 to 1.68 cm3/g for oil-wet sandstone and from 1.04 to 1.2 cm3/g for untreated samples, both at 25 °C. This suggests a pronounced affinity of CH4 for the aged rock. The adsorption capacity of the H2-CH4 mixture increases from 1.2 to 1.68 cm3/g at 80 bar and 25 °C when rock samples are exposed to crude oil compared with the untreated rock samples. Investigating the impact of temperature on adsorption capacity reveals a decrease in gas uptake as the measurement temperature rises from 25 to 60 °C across all pressure levels. All rock samples exhibit a positive hysteresis in adsorption and desorption isotherms at various temperatures. The Freundlich, Redlich-Peterson, and Sips models are found to be more representative in describing the adsorption characteristics, suggesting multilayer adsorption on the rock surface. Our findings provide insights into the impact of natural gas adsorption and desorption on overall hydrogen production. This study can improve the accuracy and efficacy of reservoir simulations and flow models that depict the movement of hydrogen and natural gas through porous media within sandstone reservoirs.

Effect of Titanium Dioxide Nanoparticles on Surfactants and Their Impact on the Interfacial Properties of the Oil-Water-Rock System.

The application of nanoparticles (NPs) in the oil and gas industry has received wide attention in recent years because it is increasingly being considered a promising approach to recovering trapped oil in conventional hydrocarbon reservoirs. Numerous studies have demonstrated that combining nanoparticles with a surfactant can enhance surfactant performance by changing the interfacial properties of the solution when it comes in contact with crude oil and rock surfaces. However, more information and additional experimental data are required concerning the application of titanium dioxide nanoparticles in alkyl ethoxy carboxylic surfactants. In this study, we measure the changes in interfacial tension and wettability due to the addition of titanium dioxide nanoparticles (0, 100, 250, and 500 ppm) in alkyl ethoxy carboxylic surfactant using a spinning drop tensiometer and contact angle measurements. The interfacial tension of the crude oil-water (surfactant) system decreases by approximately two orders of magnitude with an increasing titanium dioxide concentration, exhibiting a minimum value of 5.85 × 10-5 mN/m. Similarly, the contact angle decreases on the surface of the Berea sandstone by combining the surfactant with titanium dioxide, reaching a minimum contact angle of 8.8°. These results demonstrate the potential of this new approach to maximize the recovery of trapped oil and significantly improve oil production.

Sub-volume analysis of pore-network simulations: Determining the asymptotic longitudinal dispersion coefficient

This work introduces a new method called sub-volume analysis (SVA) to calculate macroscopic model parameters with their uncertainties from pore-scale simulations. We apply the SVA to calculate the longitudinal dispersion coefficient of the advection–dispersion model (ADM) from continuous tracer injection problems simulated with pore-network models. The SVA application presented here allows for verifying if a given network has enough length to reach an asymptotic dispersion regime where ADM applies. We tested the method using statistically constructed pore networks and pore networks built by joining several network units extracted from Berea sandstone images. There is complete agreement within the error margins for the asymptotic longitudinal dispersion coefficients obtained with the SVA and those obtained from breakthrough curve fitting. We also showed that the SVA gives more accurate results than those from the breakthrough curve fitting and much more accurate results than those from the method of spatial moments. Unlike the other methods, the SVA estimates the parameter uncertainty using a single pore-network realization.

Effect of wettability and phase distribution on critical salt concentration for fines migration initiation in sandstone reservoirs

Fines migration in sandstone oil reservoirs during different field operations is influenced by the salinity of injected brine. When salinity drops below a critical salt concentration (CSC), fines migration is initiated, leading to pore throat blockage and formation damage. Factors such as rock wettability, fluid type, fines size and concentration, and flow rate contribute to the severity of this issue. However, the impact of phase distribution and rock wettability on the CSC remains unexplored. Most results are reported for water-wet systems, but in many cases, assuming a strong water-wet state is not accurate. The current research fills that gap and provides new insights by investigating the relationship between the CSC, phase distribution, and rock wettability.Upper Berea sandstone cores were used in this study, and the CSC was experimentally determined. Brine was injected into strong water-wet and weak water-wet core samples. The injection brine salinity was gradually reduced to identify the salinity at which fines migration initiated within the core. The analysis of pressure drops and effluent analysis was applied to estimate CSC at different wettability states.The step-by-step reduction in salinity led to CSCs of 0.12 M and 0.09 M NaCl for the weak water-wet core and strong water-wet core in the presence of oil, respectively. A weak water-wet system results in a higher CSC value compared to a strong water-wet system because fine particles are contained within a thin water film, and weak water wettability facilitates their easy migration under low reduced salinity conditions. The CSC corresponded to the point of maximum pressure difference and the highest concentrations of produced fines. The findings of this research provide valuable insights into the significant influence of rock wettability and phase distribution on the initiation of fines migration. These parameters must be carefully determined and considered during the design phase of production and enhanced oil recovery in sandstone reservoirs to ensure efficient operations.

Ultrasonic S‐wave indirectly detects the very narrow gap at contact of grains: Glass beads and Ottawa sands

AbstractConsiderably different from sandstones, sands have point‐like contact of grains. In contrast, sandstones have cementation between grains, which has diminished the very narrow gap at contact of grains. In this paper, ultrasonic S‐wave in brine‐saturated glass beads and Ottawa sands is used to detect the very narrow space at contact of grains. The data of the dry beads/sands and brine are inputted into Biot theory to yield phase velocity of the saturated beads/sands. By fitting the theoretical velocity with the ultrasonic measurement, phase velocity, the quality factor and S‐wave permeability are determined as functions of frequency. The predicted ultrasonic quality factors appear to be very close to that of water‐saturated Berea sandstone. Our previous study showed that for Berea sandstone, the low‐frequency S‐wave permeability is approximately half of Darcy permeability. However, for glass beads and Ottawa sands, the S‐wave permeabilities at low frequencies are one‐order magnitude lower than Darcy permeabilities. This well shows that S‐wave permeability of the beads/sands is associated with the very narrow gap at contact of grains which is successfully detected by ultrasonic S‐wave in the indirect way.

Application of Organic Petrology and Raman Spectroscopy in Thermal Maturity Determination of the Karoo Basin (RSA) Shale Samples

An assessment performed using raman spectroscopy has found space in the black shales of the Cisuralian-age rocks of the Karoo Basin in South Africa, particularly those from the Guadalupian Ripon, Cisuralian Whitehill and Prince Albert Formations. It is used in conjunction with geochemical screening techniques such as organic petrology and programmed pyrolysis. In turn, the combination of these techniques is used for the assessment of the thermal maturity of the sedimentary organic matter from the perspective of hydrocarbon generation, retention, and expulsion. To provide further understanding of the black shales in the Cisuralian-age rocks of the Karoo Basin in South Africa, this study focuses on the characterization of samples from the KWV−01 borehole drilled in the southeastern Karoo Basin. In addition, the USA Devonian/Carboniferous Berea Sandstone project samples were included for comparison, and were used as a quality assurance measure. Organic petrology was utilized to assess the organic quality and thermal maturity of the black shales. The results obtained showed that the Karoo Basin shales are overmature, containing an abundance of solid bitumen, and this often characterizes a shale reservoir with moveable hydrocarbons (shale gas). The programmed pyrolysis analysis conducted on the black shales of the Karoo Basin yielded artifact results, as they were determined from a very low and poorly defined S2 peak. This indicated the shales to be overmature and categorized them to be of poor hydrocarbon generation potential. Raman spectroscopy was used to gain insights about the molecular structure of the black shales and to assess if this technique could be used as a complimentary tool to determine the thermal maturity of the shale samples. Raman parameters such as G–D1 Band separation, G and D1 band full width at half maximum (Gfwhm and D1fwhm) and G band position were successfully correlated with vitrinite reflectance (RoV), demonstrating a good potential for Raman spectroscopy to predict the thermal maturity of the shales. Overall, the study provides valuable information and knowledge concerning black shale sample characterization (particularly the thermal maturity and molecular structural characterization) in the Karoo Basin, South Africa.

Three-Dimensional Printing of Synthetic Core Plugs as an Alternative to Natural Core Plugs: Experimental and Numerical Study

This paper proposes three-dimensional (3D) additive fabrication of synthetic core plugs for core flooding experiments from spheres and grains of Berea Sandstone using a digital particle packing approach. Samples were generated by systematically combining the main textural parameters of the rock reservoir to design synthetic core plugs Numerical flow simulation was per-formed using the lattice Boltzmann method (LBM) to verify the flow distribution and permeability for comparison with the experimentally measured permeability and to that obtained from correlations in the literature. The digital porosity of the sample was compared to the porosity measured using an HEP-P helium porosimeter. The numerical and experimental results for permeability and porosity differed by a maximum of 18%.

Pore size distribution measurement with magnetic resonance [formula omitted] distributions outside the fast diffusion regime

Based on Brownstein-Tarr (BT) theory, a new method is proposed to determine the pore size distribution which is an important petrophysical property in studying fluid storage and fluid transport in reservoir rocks. For reservoir rocks with large pores, or high surface relaxivity, direct conversion from the magnetic resonance (MR) T2 distribution with the fast diffusion assumption may be unreliable. In this study, the ground mode lifetime T20 distribution was proposed to be utilized to estimate the pore size distribution. The T20 lifetime of large pores within a porous system can be determined directly through experiment. However, the T20 lifetimes of smaller pores may overlap with the first nonground mode T21 lifetimes of the larger pores, which collectively contribute to the MR signal with a shorter lifetime. To accurately determine the T20 lifetime of smaller pores, it is essential to remove the contribution to the distribution of the T21 lifetimes of the larger pores. The T21 distribution can be both experimentally observed and calculated through the proposed method. The proposed pore size distribution method is verified by calculation in the present work. Water-saturated glass bead packs were employed for initial experiments. The calculated pore size, and its distribution, match the geometric pore size. The proposed method was applied to determine the pore size distribution of a Berea sandstone. The results are in good agreement with SEM measurements.

Evaluation of the coupled impact of silicon oxide nanoparticles and low-salinity water on the wettability alteration of Berea sandstones

This study investigated experimentally the coupled effects of hydrophilic SiO2 nanoparticles (NPs) and low-salinity water (LSW) on the wettability of synthetic clay-free Berea sandstone. Capillary pressure, interfacial tension (IFT), contact angle, Zeta potential, and dynamic displacement measurements were performed at various NP mass fractions and brine salinities. The U.S. Bureau of Mines (USBM) index was used to quantify the wettability alteration. Furthermore, the NP stability and retention and the effect of enhanced oil recovery by nanofluid were examined. The results showed that LSW immiscible displacement with NPs altered the wettability toward more water wet. With the decreasing brine salinity and increasing NP mass fraction, the IFT and contact angle decreased. The wettability alteration intensified most as the brine salinity decreased to 4000 mg/L and the NP mass fraction increased to 0.075%. Under these conditions, the resulting incremental oil recovery factor was approximately 13 percentage points. When the brine salinity was 4000 mg/L and the NP mass fraction was 0.025%, the retention of NPs caused the minimum damage to permeability.

Applicability of 2D algorithms for 3D characterization in digital rocks physics: an example of a machine learning-based super resolution image generation

Digital rock physics is based on imaging, segmentation and numerical computations of rock samples. Due to challenges regarding the handling of a large 3-dimensional (3D) sample, 2D algorithms have always been attractive. However, in 2D algorithms, the efficiency of the pore structures in the third direction of the generated 3D sample is always questionable. We used four individually captured µCT-images of a given Berea sandstone with different resolutions (12.922, 9.499, 5.775, and 3.436 µm) to evaluate the super-resolution 3D images generated by multistep Super Resolution Double-U-Net (SRDUN), a 2D algorithm. Results show that unrealistic features form in the third direction due to section-wise reconstruction of 2D images. To overcome this issue, we suggest to generate three 3D samples using SRDUN in different directions and then to use one of two strategies: compute the average sample (reconstruction by averaging) or segment one-directional samples and combine them together (binary combination). We numerically compute rock physical properties (porosity, connected porosity, P- and S-wave velocity, permeability and formation factor) to evaluate these models. Results reveal that compared to one-directional samples, harmonic averaging leads to a sample with more similar properties to the original sample. On the other hand, rock physics trends can be calculated using a binary combination strategy by generating low, medium and high porosity samples. These trends are compatible with the properties obtained from one-directional and averaged samples as long as the scale difference between the input and output images of SRDUN is small enough (less than about 3 in our case). By increasing the scale difference, more dispersed results are obtained.

Direct prediction of relative permeability curve from 3D digital rock images based on deep learning approaches

The relative permeability curve is one of the key features to evaluate the flow property of a porous medium, which is important in petroleum and gas industry, yet it is not easy to obtain. In this study, we proposed a new intelligent way to predict the relative permeability curves directly from 3D digital rock images, compared with other existing artificial intelligence (AI) methods that usually used indirect geometrical parameters as inputs. The inputs of our AI model are the digital rock images and fluid/rock physical properties such as wettability and interfacial tension; the outputs (relative permeability curves) are obtained by an improved pore-network model. We test three deep learning methods (CNN, ConvLSTM-FC, and ConvLSTM-CNN) and compare their accuracy in the predictions for both sandstone and volcanic rock types. The results show that the overall prediction accuracy of the deep hybrid ConvLSTM-CNN method is the highest, reaching 95%. The well-trained model is further applied to successfully predict the effects of wettability and interfacial tension on the relative permeability curves of a Berea sandstone.

Transverse relaxation measurements for moving samples in the presence of strong magnetic field gradients

Nuclear Magnetic Resonance (NMR) is one of the primary techniques used in the oil industry for logging operations and in the laboratory environment to study rock formations due to its reliability in offering a reliable estimation of oil well productivity. Two types of well-logging operations exist, Wireline Logging and Logging While Drilling (LWD). Wireline Logging involves NMR measurements taken under static conditions. In contrast, LWD involves measurements taken during the drilling process while the tool is in motion, translating, rotating, and vibrating relative to the formation. To understand the behavior of NMR signals measured under LWD conditions on a laboratory scale, we developed a setup that includes a single-sided magnet, rf probes, and a mechanical system that emulates a relative sinusoidal motion between the sample and the applied magnetic field. Four representative rock samples were selected according to their relaxation times, which were short, intermediate, and long compared to the oscillation period of the LWD simulator: three sandstone, Fontainebleau, Berea Sandstone, and Portland Red, and one carbonate, Indiana Limestone. The results show that even with the modifications observed in the relaxation times distribution, which could lead to misinterpreting the geological formation parameters, the total porosity remains unaffected and independent of the sample motion during the NMR measurements, even under severe conditions and using the standard procedures of the data processing.

Analysis of reconstructed multisource and multiscale 3-D digital rocks based on the cycle-consistent generative adversarial network method

SUMMARY Digital rock physics (DRP) is important for characterizing the pore characteristics and petrophysical parameters of rocks from a microscopic perspective. Among the digital rock reconstruction methods, the most widely used is the computer tomography (CT) scan method. However, the pore structure of rocks has multiscale features, and CT scan images with a single resolution cannot completely describe the pore structure characteristics of rocks. In this paper, we analysed reconstructed multisource and multiscale 3-D digital rocks based on the cycle-consistent generative adversarial network (CycleGAN) method. This method fully integrates the advantages of the large field of view of low-resolution images and the high-precision features of high-resolution images. To investigate the performance of the method, two sequences of CT scan images of a sandstone (sample A) and a carbonate rock (sample B) collected from oilfields were studied. Moreover, due to the high resolution of scanning electron microscope (SEM) images, we also constructed 3-D digital rocks with different resolutions of the Berea sandstone based on the combination of CT scan images and SEM images. Finally, the statistical properties and absolute permeabilities were calculated to evaluate the accuracies of reconstructed multisource and multiscale 3-D digital rocks. The results show that the reconstructed multiscale digital rocks based on the CycleGAN method have good accuracy in terms of statistical properties and petrophysical properties. Considering the computational cost and computational accuracy, for high- and low-resolution CT scan images and CT scan images with SEM images as training image data sources, we suggest that the resolution of the reconstructed multiscale digital cores is 4–8 times and 4–16 times higher than that of the low-resolution CT scan images, respectively. The findings of our research will be helpful in gaining insight into the petrophysical properties of heterogeneous rocks.

The effect of surface properties of silicon dioxide nanoparticle in drilling fluid on return permeability

The oil and gas industry faces significant challenges in drilling and completion operations, particularly with respect to formation damage and wellbore instability. One approach to mitigating these issues is the use of nanoparticle-enhanced drilling fluids, which can improve fluid filtration and reduce formation damage. However, the influence of nanoparticle surface properties on these effects is not well understood. Therefore, the aim of this study is to investigate the influence of the zeta potential of nanoparticles in drilling fluids on the filtration of drilling fluids and its effect on the permeability of porous media. The motivation behind this work is to enhance the understanding of the role of nanoparticle surface properties in improving drilling fluid filtration and reducing formation damage. The novelty of this work lies in the exploration of the influence of nanoparticle surface properties on the return permeability of porous media. Silicon dioxides were used to represent the nanoparticles, and the surface was modified by silanization with a carboxyl group. Filtration and permeability alteration were analyzed using return permeability experiments on Berea sandstone cores under overburden pressure, pore pressure, overbalance pressure, and temperatures of 3000 psi (20.68 MPa), 1000 psi (6.89 MPa), 500 psi (3.45 MPa), and 140 °F (60 °C), respectively. Bentonite-free water-based drilling fluid and sodium chloride brine were used to represent the formation fluids. The results show that the addition of non-functionalized SiO2, and low and high carboxyl functionalized SiO2 reduced the filtration by 13%, 33%, and 36%, respectively. Although the addition of nanoparticles into the drilling fluid can reduce fluid invasion into the porous media, solid invasion into the porous media can be detrimental and cannot be easily remediated in recovering return permeability. Return permeability of porous media after exposure to drilling fluids without nanoparticles and with non-functionalized SiO2 decreased by 47% and 82%, respectively. In contrast, exposure to drilling fluid with low and high carboxyl functionalized SiO2 decreased only by 21% and 15%, indicating the importance of nanoparticle surface properties in increasing the return permeability of porous media.