Tools for pressure core sub-coring and pore-scale micro-CT (computed tomography) scans

The pore habits of gas hydrate in natural sediment matrices provide essential clues for understanding physical (mechanical, thermal, hydraulic, and electrical) properties of hydrate-bearing sediments, yet there are no tools that can directly visualize the pore habits of natural gas hydrate other than indirect interpretation based on core-scale or field-scale observations. A significant challenge is to obtain a mini-core from pressure cores retrieved from natural reservoirs for high-resolution micro-CT (computed tomography) scans while maintaining pressure and temperature conditions required for stability of gas hydrate during all operational steps including manipulation, cutting, transferring, sub-coring and CT scanning. We present a new set of tools for pore-scale micro-CT imaging of natural hydrate-bearing sediments while maintaining pressure and temperature control. The tests with laboratory-prepared cores and pressure cores successfully demonstrate the capability of this set of tools to subsample a mini-core from pressure cores, transfer the mini-core to an X-ray transparent core holder, and conduct micro-CT scans. Successfully obtained CT images prove the functionality of this set of tools.

Effects of Pressurizing Cryogenic Treatments on Physical and Mechanical Properties of Shale Core Samples—An Experimental Study

The technique of cryogenic treatments requires injecting extremely cold fluids such as liquid nitrogen (LN2) into formations to create fractures in addition to connecting pre-existing fracture networks. This study investigated the effects of implementing and pressurizing cryogenic treatment on the physical (porosity and permeability) and mechanical properties (Young’s modulus, Poisson’s ratio, and bulk compressibility) of the Marcellus shale samples. Ten Marcellus core samples were inserted in a core holder and heated to 66 °C using an oven. Then, LN2 (−177 °C) was injected into the samples at approximately 0.14 MPa. Nitrogen was used to pressurize nine samples at injection pressures of 1.38, 2.76, and 4.14 MPa while the tenth core sample was not pressurized. Using a cryogenic pressure transducer and a T-type thermocouple, the pressure and temperature of the core holder were monitored and recorded during the test. The core samples were scanned using a computed tomography (CT) scanner, and their porosities, permeability, and ultrasonic velocities were measured both before and after conducting the cryogenic treatments. The analyses of CT scan results illustrated that conducting cryogenic treatments created new cracks inside all the samples. These cracks increased the pore volume, and as a result, the porosity, permeability, and bulk compressibility of the core samples increased. The creations of the new cracks also resulted in reductions in the compressional and shear velocities of the samples, and as a result, decreasing the Young’s modulus and Poisson’s ratio. Moreover, the results revealed that pressurizing the injected LN2 increased the alterations of aforementioned properties.

Characterization of an electrically conductive proppant for fracture diagnostics

Fracture diagnosis with electromagnetic (EM) and electrical tools requires proppants with high electrical conductivity and mechanical strength. Lab measurements of the electrical and hydraulic conductivity of proppants are critical for selecting the best candidates. Such measurements greatly benefit simulations, field tests, and the ultimate application of such proppants in the field. To that end, a new lab protocol is developed for measuring the electrical and hydraulic conductivity of proppants. The lab setup, which mainly includes a resistivity core holder and a Hassler sleeve core holder, allows for simulation of realistic pressure and temperature conditions when making measurements. Petroleum coke (PC) is proposed as a candidate proppant because of its widespread availability and low cost. Lab measurements show that the effective electrical conductivity of pure PC in a model fracture is approximately 5000 S/m, under a closure stress greater than [Formula: see text] (4000 psi). When PC is mixed with sand, the effective electrical conductivity of the mixture decreases with an increasing weight percentage of sand. Although sand degrades the contact between PC particles, the electrical conductivity stays reasonably high (approximately 1700 S/m) when 50% sand is added. Hydraulic conductivity measurements show that when a fracture is propped with pure PC, the measured fracture conductivity is greater than [Formula: see text] ([Formula: see text]) (dimensionless fracture conductivity greater than 100 for a shale with [Formula: see text] or 100 nD permeability) under a confining pressure of [Formula: see text] (6000 psi). This means that a fracture propped with PC is infinitely conductive in a typical shale formation. When sand is added, the fracture’s hydraulic conductivity becomes even higher, which clearly shows PC’s ability of sustaining high stresses. The proposed protocol provides a robust and effective method that can be generalized for lab testing for other candidate proppants. The data presented clearly show that PC has the potential for field-scale applications in EM hydraulic fracture diagnostics.

The Effects of Hydro Confining Pressure on the Flow Properties of Sandstone and Carbonate Rocks

There is a significant effect of the hydro confining pressure of the core holder on the flowing properties of the formation rocks. This effect is caused due to the mechanical elastic deformation of the core when carrying outlaboratory studies of the waterproof and polymer compositions. Consequently, this deformation will cause changing in the permeability and voids storage capacity of the studied core samples. Therefore, under the laboratory conditions and when dealing with such studies on formation cores, it is necessary to consider the changes of permeability and voids storage capacity of these cores.

Wirelessly Powered Microchips for Mapping Hydraulic Fractures

Summary The onset of the era of internet of things and artificial intelligence comes with the ever-growing demand for self-sustaining and efficient sensors. Sensors based on complementary metal oxide semiconductors (CMOSs) have attracted significant attention in the implementation of distributed sensor systems for a vast number of applications because of their economical and complex integration benefits. In this work, we report CMOS-based energy-harvesting chips as wireless nodes for mapping hydraulic fractures during the shale gas extraction process. The CMOS chips are tested in a custom benchtop core-holder chamber that emulates a downhole environment. An induction coil, sized at 5 × 5 mm, connected to a custom CMOS chip, is used as a receiver inside the core holder to harvest electromagnetic (EM) energy transmitted by an external antenna. On the basis of the custom core-holder experiment, it is shown that encapsulated CMOS chips are able to harvest EM energy and thereby operate wirelessly. The receiver has a resonance frequency of 198 MHz. The CMOS chip is equipped with an integrated power management unit (PMU), energy-harvesting unit, and a signal-generation block. The CMOS chip inside the chamber produces an output signal with a frequency proportional to the harvested power. By measuring the frequency of the output signal produced by the chip, we are able to localize the chips within the rock inside the custom core holder.

Monitoring gas hydrate formation with magnetic resonance imaging in a metallic core holder

Methane hydrate deposits world-wide are promising sources of natural gas. Magnetic Resonance Imaging (MRI) has proven useful in previous studies of hydrate formation. In the present work, methane hydrate formation in a water saturated sand pack was investigated employing an MRI-compatible metallic core holder at low magnetic field with a suite of advanced MRI methods developed at the UNB MRI Centre. The new MRI methods are intended to permit observation and quantification of residual fluids in the pore space as hydrate forms. Hydrate formation occurred in the water-saturated sand at 1500 psi and 4 °C. The core holder has a maximum working pressure of 4000 psi between -28 and 80 °C. The heat-exchange jacket enclosing the core holder enabled very precise control of the sample temperature. A pure phase encode MRI technique, SPRITE, and a bulk T1-T2 MR method provided high quality measurements of pore fluid saturation. Rapid 1D SPRITE MRI measurements time resolved the disappearance of pore water and hence the growth of hydrate in the sand pack. 3D π-EPI images confirmed that the residual water was inhomogeneously distributed along the sand pack. Bulk T1-T2 measurements discriminated residual water from the pore gas during the hydrate formation. A recently published local T1-T2 method helped discriminate bulk gas from the residual fluids in the sample. Hydrate formation commenced within two hours of gas supply. Hydrate formed throughout the sand pack, but maximum hydrate was observed at the interface between the gas pressure head and the sand pack. This irregular pattern of hydrate formation became more uniform over 24 hours. The rate of hydrate formation was greatest in the first two hours of reaction. An SE-SPI T2 map showed the T2 distribution changed considerably in space and time as hydrate formation continued. Changes in the T2 distribution are interpreted as pore level changes in residual water content and environment.