At the nanometer scale, materials behave differently. No one really knows how natural gas flows at that level. With the novel single-molecule imaging system which is designed in Missouri S&T, it is possible to directly monitor the flowing behavior of natural gas, polymer solutions and surfactants in nano-pores, individually or simultaneously.This can be used for new flow model developments and correlated with mathematical models.

2. Submicron Scale Pore Imaging

The dual-beam system (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) has been widely used in material science studies. It is especially useful for three-dimensional microscopy and material characterization. It is currently considered the best method for sectioning and imaging the microstructure of gas shale samples. Its electron gun offers in situ imaging, and the focused ion beam provides simultaneous sequential milling. FIB milling gun uses Ga+ ions accelerated at high voltage to bombard the shale surface and sputter away material via momentum transfer. Many electron detectors are associated with a dual-beam microscope. The ejected electrons included secondary electrons (SE) and backscattered electrons (BSE) for imaging. An energy dispersive spectroscope (EDS) detector permitted element mapping.

SEM pictures of shale gas rocks taken in Missouri S&T

3. 3D Pore Reconstruction

By collecting and stacking two-dimensional SEM images for different layers of shale gas rocks, the original pore structure in a three-dimensional model can be reconstructed. The model provides insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy.

Adapted from SPE Paper 144050 (Missouri S&T, 2011)

4. Mercury Injection Porosimetry

Mercury injection porosimetry is an analytical technique for determining distribution of pore-throat sizes, understanding the structures of pore systems in the reservoir, is capillary pressure analysis. Porous media consists of pores and smaller channels (pore throats) connecting the pores. Pore throats, in conjunction with pore-system geometry and topology, control the movement of fluids. Through the use of capillary pressure curves derived from mercury porosimetry, it is possible to calculate pore-throat size and distribution.

Mercury injection porosimetry is based on the measurement of the volume distribution of pore throats; the method is based on forcing mercury into small voids, pore throads, within the rock sample which has been previously evacuated. By injection mercury at incrementally higher pressures, and allowing time for equilibration between pressure increments, mercury is injected into increasingly small pores. It is then capable to calculate the size distribution of pore throats, to determine how pore-throat size is affected by increasing confining stress to approximate reservoir conditions, and to determine how permeability is affected by reduction in pore-throat size.

Adapted from SPE Paper 144050 (Missouri S&T, 2011)

5. Rock Wettability Test/Contact Angle Measurement

Shale gas rocks are usually hydraulically fractured in order to be capable to produce gas. Chemical additives such as friction reducers and viscosifiers have often been added into fracturing fluids. However, the additives in fracturing fluids may impair the fracture permeability and alter the rock wettability which influences the gas flow ability. To fully understand this problem, intensive study of rock surface and fluid composition interaction needs to be performed. Rock wettability is basically defined by the contact angle measure. The goniometer in our lab can be used to measure the contact angle of various fluids on the shale rock surfaces thus to determine the rock wettability for various gas shales.

6. XRD/Clay Mineralogy

As known that clay minerals are very fine grained that X-ray methods, rather than hand specimen or optical methods, are used to identify them. Moreover, clay structure is three dimensional and varies considerably from one type of clay to another. X-Ray diffraction is considered to be the best method in defining clay minerals. By applying the modified procedure for semi-quantification of clay minerals, the identification of individual minerals in shale gas samples can provide valuable information for rock analysis.

7. Kerogen Analysis

With palynofacies and TOC analysis, some important geochemical parameters such as Kerogen type, thermal maturation,and vitrinite reflectance can be easily determined to fully understand the shale gas rock's source potential.

Adapted from SPE Paper 144267 (Missouri S&T, 2011)

8. NMR Core Analysis

Low field nuclear magnetic resonance, NMR, is routinely used in the oil exploration industry to examine the relaxation time distribution of fluids in core plugs. These distributions can be interpreted to give information on pore size distributions, permeability, porosity, free fluid index and bound water volumes.