Removing formation damage and stimulation of deep illitic-sandstone reservoirs using green fluids

Illitic-sandstone reservoirs are very sensitive to HCl-based fluids. When HCl contacts illitic-sandstone it breaks down and causes fines migration and formation damage. The migration of fines through the porous media will block the pores, reduce permeability and decrease the production rate of oil and gas wells. Literature showed that all clay minerals are essentially unstable in HCl at temperatures greater than 300°F. In turn, there is an essential need to look for stimulation fluids other than HCl to stimulate deep sandstone reservoirs. Alternative fluids to HCl/HF mud acids were introduced to stimulate and remove the damage from illitic-sandstone reservoirs. These fluids are chelating agents such as EDTA (ethylene diamine tetraacetic acid), HEDTA (hydroxyl ethylene diaminetriacetic acid), and GLDA (glutamic acid-N,N-diacetic acid). In this study, sandstone cores with different illite contents were examined. Illite content of 1, 10, 14, and 18 wt% of the sandstone cores were used in the coreflood experiments at 300°F. Different combinations of GLDA/HF were tested to determine the optimum ratio of GLDA/HF. CT scan and permeability measurements before and after the treatment were used to assess the effectiveness of each fluid in removing the damage and stimulation of sandstone cores. Our results showed that 15 wt% HCl caused severe damage to sandstone cores with different illite contents. GLDA, HEDTA, and EDTA showed a good compatibility with the illitic-sandstone cores at 300°F. Permeability measurements and CT scan results showed that GLDA performed better than HEDTA and EDTA at pH of 4. The optimum ratio of GLDA/HF concentration was found to be 20 wt% GLDA/1 wt% HF, which gives the maximum increase in core permeability. The three fluids tested in this study showed good compatibility with illite. They can be used to stimulate illitic-sandstone reservoirs alone or in combination with HF acid. GLDA was found to be compatible with the sandstone cores that contained up to 18 wt%. No sands deconsolidation was noted with any of the three fluids. The results obtained from this study will significantly improve the outcome of acid treatments in illitic-sandstone reservoirs at high temperatures.