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Information acquisition and analysis of oil reservoirs are one of the most challenging and scientifically demanding areas in the oil exploration industry. Herein, we report a single-step solvothermal method for the synthesis of highly-stable hydrophilic and hydrophobic superparamagnetic iron oxide nanoparticles (SPIONs) as T2-contrast agents for oil reservoir applications. Hydrophilic and hydrophobic characteristics on the surfaces of SPIONs were achieved using polyethylene glycol (PEG-400) and oleylamine (OLA) for water/oil phases of the reservoir, respectively. For comparison, uncoated SPIONs were also prepared by coprecipitation method using NH4OH as a reducing agent. Stability of hydrophilic SPIONs was monitored in deionized (DI) water and/or artificial seawater (ASW), while stability of hydrophobic SPIONs was investigated in model oil (cyclohexane-hexadecane 1:1). X-ray diffraction (XRD) and X-ray photoelectron spectroscopy (XPS) profiles confirm the magnetite (Fe3O4) phase of synthesized nanoparticles (NPs). The presence of C−O (532.4 eV) and −NH2 (399.7 eV) in XPS spectra of N1s and O1s substantiate the surface functionalization of Fe3O4 NPs with PEG and OLA, respectively. Transmission electron microscopy (TEM) images demonstrate the spherical shape NPs having particle diameters 11.6 ± 1.4, 12.7 ± 2.2 and 9.1 ± 3.0 for PEG-Fe3O4, OLA-Fe3O4, and Fe3O4, respectively. NMR T2-relaxation measurements were performed first time by an acorn area analyzer to demonstrate meaningful results for targeted reservoir applications. The transversal relaxivity (r2) values for PEG-Fe3O4 (66.7 mM-1 s-1) and OLA-Fe3O4 (49.0 mM-1 s-1) were 2.07 and 1.53 times higher than Fe3O4 (32.2 mM-1 s-1) NPs, respectively. The observed (i) quenching of T2-relaxation signals with SPION concentration, (ii) excellent relaxivity properties due to their ultra-small size, and (iii) long-term stability in different media, suggest them to be promising T2contrast agents for oil reservoir applications.

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Permeability determination of organic-rich shales is still a major challenge. Uncertainty in this estimate involves several factors. Two significant ones are the occurrence of gas adsorption which can severely limit gas transport in the pores and understanding the physical chemistry issues of the pore's surface area estimation when using various gases. In this study, we reported our experimental results of permeability measurement on several unconventional shale samples, and investigated the effect of gas type, pore pressure, effective stress and sample orientation on the measured permeabilities.Permeability of shale samples is measured using the complex pressure transient technique. Three different gases, argon, nitrogen, and carbon dioxide, are used as permeating fluid through the samples. Experiments are conducted isothermally at various pore and confining pressures that maintain a constant net effective stress. Generally, samples have higher measured permeabilities when using nitrogen as pore fluid rather than using argon. The discrepancy was attributed to different adsorption potentials between argon and nitrogen: Argon has a similar sorption potential to methane while nitrogen's sorption potential is relatively weak. As expected, the measured permeability of all samples decreases when the pore pressure increases reflecting the reduction in the gas slippage effect. Samples from the same whole core display permeability anisotropy: Horizontal plugs cut parallel to bedding have a higher measured permeability, which is in the range of microdarcy, while the permeability of vertical plugs cut perpendicular to bedding is in the range of nanodarcy. This anisotropy behavior is believed to be caused by the fractures contained within the horizontal samples. The measured permeability is observed to decease with increasing effective stress acting on the samples. This reduction behaves differently: Permeability decreases very slowly when the increasing effective stress is resulted from the decrease of the pore pressure. The enhanced Klinkenberg effect due to the decreasing pore pressure compensates at least partly the permeability reduction resulting from increasing effective stress. However, permeability reduces dramatically when the effective stress increases because of the increasing confining pressure. In this case, the flow channels may be reduced or even closed, thus blocking the flow of gas.

Accurate determination of organic-rich shale permeability is still a major challenge. Various methods have been proposed to measure the permeability on core plugs or crushed samples under various stress conditions using different fluids. Permeability obtained from core plugs and their crushed samples could differ by two orders of magnitude, potentially painting very different views of the reservoirs and resulting in differences in asset development workflows. This situation only reinforces the need for considerable additional focused work to quantify tight rock permeability and better understand the measurement method dependence. This paper presents the experimental comparison of three different unsteady-state transient methods for measuring the permeability of organic-rich shale plugs: pressure build-up, pulse-decay and oscillating pulse techniques. Permeability measurements are conducted isothermally using nitrogen gas on core plugs from the Barnett, Eagle Ford, Marcellus and Mancos formations at the same confining pressure and pore pressure. These plugs differ in mineralogy, total organic carbon (TOC), nuclear magnetic resonance (NMR) and helium porosity. Fractures are observed through the horizontal samples along the gas flow direction, while vertical samples do not have fractures. For each plug, the permeability tests begin with the pressure build-up measurement, and are followed sequentially by the pulse-decay and oscillating pulse methods whenever applicable. The plugs are then cut into smaller sizes for continuation of permeability tests and investigation of the permeability dependence on the plug size. For the samples analyzed, the permeability measured from the pulse-decay method is essentially identical to that from the oscillating pulse method. Compared to these two methods, the pressure build­up test generally gives a relatively higher value when requiring an independent porosity measurement to compute the permeability, while it gives a relatively lower value when no porosity is needed. However, the permeability difference among these methods is generally small. This indicates that the pressure build-up test can be used to perform permeability measurement on large core plugs that cannot be tested using the pulse-decay or oscillating pulse methods. There is no trend observed on the permeability dependence on the plug sizes used. Depending on fracture distribution and connectivity, the measured permeability of horizontal samples is randomly affected by the sample sizes, indicating multiple samples with various sizes may be required to obtain a representative permeability value for horizontal plugs. Vertical plugs show little permeability dependence on the sample sizes. Consequently, a small vertical plug can be used for very tight rocks enabling quicker matrix permeability measurements.