RESUMEN
In the Changqing area, over 23.6% of gas wells produce less than 0.1 × 104 m3/d of gas daily, posing a challenge to gas field sustainability. Laboratory analysis of scale samples from three wells and formation water analysis via inductively coupled plasma revealed soluble salt as the primary well blockage, with sodium chloride and calcium chloride comprising 48.0-81.2% of total content. The G3# well blockage contains a small amount of quartz from acid-insoluble components of carbonate acidification. Formation water from all wells exhibited high salinity (up to 153 g/L) with a calcium chloride water type. Scanning electron microscopy and EDS confirmed halite and quartz features in blockage samples. Theoretical calculations show salt crystallization when tubing pressure falls below 10 MPa and daily water production is <1.0 tons/day. Lower production leads to lower tubing pressure and higher salt precipitation at the bottom of the well. For G1# and G2# blockages, HCl dissolves >90%, and water >85%, making them suitable removal agents. For 3# blockage, mud acid with >80% dissolution is recommended. Chemical methods effectively clean the wellbore and formation. Optimized blockage removal measures increase tubing pressure and daily production by 2.18 and 4.05 times, respectively. This study offers insights into addressing well blockage challenges in low-producing gas wells.
RESUMEN
Igneous rock oil and gas reservoirs have great development potential. Hydraulic fracturing is an important means for the development of these reservoirs. In the process of fracturing and increasing production, fracturing fluid is prone to a hydration reaction with clay minerals in igneous rock, and then, the structure and mechanical properties of the igneous rock are changed, affecting increased production. Therefore, it is necessary to establish a systematic water-rock reaction experiment method to understand the influence of fracturing fluid on the structure and mechanical properties of igneous rocks and to optimize the fracturing fluid system of igneous rock reservoirs. In this experiment, four solutions were used: slickwater, guar fracturing fluid, 2% KCl aqueous solution, and 4% KCl aqueous solution. Acoustic testing, porosity and permeability testing, XRD analysis, micro-CT scanning, and displacement experiments were performed. The influence of different fracturing fluids on the structure and mechanical properties of igneous rocks was studied. Igneous rock samples with a permeability of 0.05-0.1 mD and average porosity of 7-14% were used. The results show that all four liquid systems will reduce the permeability, Young's modulus, and brittleness index and increase the porosity and Poisson's ratio of the rock after fracturing. Among them, the permeability damage rate is as high as 37.37%, which may be related to the plugging of pores with solid residues in the gel breaking liquid; CT results show that there are microcracks in the rock, which increase over time, up to 13.54%. The brittleness index decreases. Among the fluids, the influence of slickwater on the rock brittleness index is the smallest, no more than 5%. Guar gum had the greatest effect on the Gel breaking liquid, up to 58%. One of the reasons for the increase in porosity is that adding a clay stabilizer composed of inorganic salts and organic cationic polymers to the slickwater fracturing fluid can effectively reduce the damage caused by the fracturing fluid to the rock during the fracturing process and can reduce the maximum by 50%. This paper can clarify the damage law of fracturing fluid systems to igneous rock reservoirs and provide the theoretical basis for the hydraulic fracturing of igneous rock reservoirs.
