Coal fines migration: A holistic review of influencing factors.

Coal fines can substantially influence coal seam gas reservoir permeability, thus impeding the flow of gas in coal microstructure. The coal fines generation and migration are influenced by several factors, wherein coal fines are generally hydrophobic and aggregate in natural coal seam gas (CSG) under prevailing conditions of pH, salinity, temperature and pressure. This aggregation behaviour can damage the coal matrix and cleat system permeabilities, leading to a considerable reduction of proppant pack conductivity (i.e. fracture conductivity). Several datasets have been reported within the literature on this subject in the last decade. However, a more up-to-date discussion of this area is key to understanding coal fines migration and associated knowledge. Thus, in this review, we conduct a systematic investigation of coal fines and their influencing factors. Here, coal fines are introduced, followed by an initial holistic investigation of their generation, plugging, movement, redistribution and production. Then, in order to enhance current understandings of the subject matter, a parametric evaluation of the factors noted earlier is conducted, based on recently published literature. Subsequently, the published mathematical and analytical models for fines generation are reviewed. Finally, the implications and challenges associated with coal fines mitigation are discussed.

Influence of mineralogy and surfactant concentration on zeta potential in intact sandstone at high pressure.

HYPOTHESIS: Zeta-potential in the presence of brine has been studied for its application within hydrocarbon reservoirs. These studies have shown that sandstone's zeta-potential remains negatively charged, non-zero, and levels-off at salinities > 0.4 mol.dm-3, thus becoming independent of salinity when ionic strength is increased further. However, research conducted to date has not yet considered clay-rich (i.e. clay ≥ 5 wt%) sandstones. EXPERIMENTS: Firstly, streaming potential measurements were conducted on Bandera Gray sandstones (clay-rich and clay-poor) with 0.6 and 2 mol.dm-3 NaCl brine-saturated in pressurised environments (6.895 MPa overburden and 3.447 MPa back-pressure). Secondly, the streaming potential was determined at identical conditions for the effect of two surfactants, SDBS and CTAB, at concentrations of 0.01 and 0.1 wt% on the clay-poor sample in 0.6 mol.dm-3 NaCl. Thirdly, a comparison of zeta potentials determined via electrophoretic and streaming potential was conducted. Accordingly, this work analyses the effects of mineralogy and surfactants within this process. FINDINGS: Clay-rich sandstone possessed lower zeta-potentials than clay-poor sandstone at the two tested salinities. SDBS reduced zeta-potential and yielded higher repulsive forces rendering the rock more hydrophilic. Additionally, electrophoretic zeta-potentials were higher when compared to streaming zeta-potentials. Mechanisms for the observed phenomena are also provided.

Effect of humic acid on CO2-wettability in sandstone formation.

HYPOTHESIS: Millions of tons of CO2 are stored in CO2 geological storage (CGS) formations (depleted oil reservoirs and deep saline aquifers) every year. These CGS formations naturally contain small concentrations of water-soluble organic components in particular humic acid (HA), which may drastically affect the rock wettability - a significant factor determining storage capacities and containment security. Hence, it is essential to characterise the effect of humic acid concentration on CO2-wettability and its associated impact on storage capacity. EXPERIMENTAL: To achieve this, we measured advancing and receding contact angles at reservoir conditions using the pendant drop tilted plate method for various humic acid concentrations (1, 10, and 100 mg/L) as a function of pressure (0.1-25 MPa), temperature (303-333 K), and brine salinity (0-0.3 M NaCl). Further, the influence of humic acid adsorption on the mineral's surface was examined by several independent techniques. RESULTS: Our results demonstrate that humic acid significantly changes rock wettability from water-wet (0-50°) towards CO2-wet (90-110°). An increase in pressure, temperature, and salinity had a similar effect. Humic acid adsorption also increased the surface roughness of the substrates. We conclude that even trace amounts of humic acid (i.e. 1 mg/L), which exist in storage aquifers, significantly increase CO2-wettability and thus reduce structural and residual trapping capacities. Therefore, it is pertinent to account for these humic acid concentrations to de-risk CGS projects.