Gas permeability (k) and porosity (φ) are the most important parameters in CBM/ECBM and CCS in deep unmineable coal seams. k and φ depend on the coal micro structure, and k and φ significantly change with varying effective stress. However, how the coal micro structure is related to such permeability and porosity changes is only poorly understood. We thus imaged sub-bituminous coal samples at two resolutions (medium-33.7 μm and high-3.43 μm voxel size) in 3D with an x-ray microcomputed tomograph as a function of applied effective stress; and investigated how cleat morphology, k and φ are influenced by the changes in effective stress and how these parameters are interrelated. In the images, three phases were identified: micro cleats (void), a mineral phase (carbonate) and the coal matrix. When effective stress increased, the cleats became narrow and closed or disconnected. This resulted in a dramatic permeability drop with increasing effective stress, while porosity decreased only linearly.

We measure the pressure difference during two‐phase flow across a sandstone sample for a range of injection rates and fractional flows of water, the wetting phase, during an imbibition experiment. We quantify the onset of a transition from a linear relationship between flow rate and pressure gradient to a nonlinear power‐law dependence. We show that the transition from linear (Darcy) to nonlinear flow and the exponent in the power‐law is a function of fractional flow. We use energy balance to accurately predict the onset of intermittency for a range of fractional flows, fluid viscosities, and different rock types.

CO2 geosequestration in oil reservoirs is an economically attractive solution as it can be combined with enhanced oil recovery (CO2‐EOR). However, the effectiveness of the associated three‐phase displacement processes has not been tested at the micrometer pore scale, which determines the overall reservoir‐scale fluid dynamics and thus CO2‐EOR project success. We thus imaged such displacement processes in situ in 3‐D with X‐ray microcomputed tomography at high resolution at reservoir conditions and found that oil extraction was enhanced substantially, while a significant residual CO2 saturation (13.5%) could be achieved in oil‐wet rock. Statistics of the residual CO2 and oil clusters are also provided; they are similar to what is found in analogue two‐phase systems although some details are different, and displacement processes are significantly more complex.

No abstract

Enhanced coalbed methane recovery and CO2 geostorage in coal seams are severely limited by permeability decrease caused by CO2 injection and associated coal matrix swelling. Typically, it is assumed that matrix swelling leads to coal cleat closure, and as a consequence, permeability is reduced. However, this assumption has not yet been directly observed. Using a novel in situ reservoir condition X‐ray microcomputed tomography flooding apparatus, for the first time we observed such microcleat closure induced by supercritical CO2 flooding in situ. Furthermore, fracturing of the mineral phase (embedded in the coal) was observed; this fracturing was induced by the internal swelling stress. We conclude that coal permeability is drastically reduced by cleat closure, which again is caused by coal matrix swelling, which again is caused by flooding with supercritical CO2.

The water contact angle in a system of brine (20 wt % CaCl2) and CO2 was measured on a smooth dolomite surface [root mean square (RMS) surface roughness of 45 nm] with both hydrophilic and hydrophobic behaviors as a function of the pressure (0.1, 5, 10, 15, and 20 MPa) and temperature (308, 323, and 343 K). The experimental results show that the contact angle of brine/CO2 increases slightly with the temperature when the dolomite surface is hydrophilic but, interestingly, reduces when the surface is hydrophobic. The results also illustrate that the brine/CO2 contact angles increase with increasing pressure. We interpreted the experimental observations using the concept of alteration in van der Waals potential (substrate surface chemistry) with thermodynamic properties, including pressure and temperature.

No abstract

The wetting characteristics of shale rocks at representative subsurface conditions remain an area of active debate. A precise characterization of shale wettability is essential for enhanced oil and gas recovery, containment security during CO 2 geo-storage, and flow back efficiency during hydraulic fracturing. While several methods were utilized in the literature to evaluate shale wettability (e.g., contact angle measurements, spontaneous imbibition method ,and NMR method), we here review the recently published data sets on shale contact angle measurements. The objectives of this review are to (a) develop a repository of the recent shale wettability data sets using contact angle measurements at high pressure and temperature (HPHT) conditions, (b) explore the factors influencing shale wettability, (c) identify potential limitations associated with contact angle methods, and (d) provide a research outlook for this area. On the basis of the data reviewed here, we conclude the following: (1) Shale/oil/brine systems demonstrate water-wet to strongly oil-wet wetting behaviors. (2) Shale/CO 2 /brine systems are usually weakly water-wet to CO 2 -wet. (3) Shale/CH 4 /brine systems are weakly water-wet. The key contributing factors that underpin this high shale wettability variability include, but are not limited to, operating pressure and temperature conditions, total organic content (TOC), mineral matter, and thermal maturity conditions. Thus, this review provides a succinct analysis of the shale wettability contact angle data sets and affords an overview of the current state of the art technology and possible future developments in this area to enhance the understanding of shale wettability.