Thermogra Essay

A first important conclusion can be drawn from the composition of the individual clay minerals. In the oil industry, shale water content is usually determined by heating a sample to 105°C in an oven until weight stabilization. Weight loss is assumed to derive from the water leaving the sample, and this water is normally called free water. As illustrated on the TGA chart of montmorillonite, interlayer water in smectites is released at temperatures below 100°C. Shales with high smectite content, even though dried in air for one year, present a significant amount of “free” water (e.g. KHF_D Even shales with almost no smectite (e.g. KHF_C), and dried for one year, present some “free” water, possibly from the illite (depending on the type it can have water bounded). Therefore, water content in a shale can be erroneously interpreted as free water. Depending on the amount of smectite (and/or illite) present in a shale, the majority of its “free” water is actually interlayer water from montmorillonite minerals.
Rock modification after exposure to a drilling fluid can be tracked, and the consequences of interaction observed. With this capability, TGA can be used to screen drilling and completion fluids, in order to improve their composition. TGA analyses can be performed periodically as the sample is exposed to a fluid. As it requires a very small sample, the same shale piece can be kept immersed and the surface periodically scratched and tested.
Another advantage of the technique is the possibility of using cuttings, which abound (preservation since the rig site must be guaranteed) and are cheaper to be obtained than cores. The only concern relates to any contamination the cuttings might have acquired (by interaction with