Tight gas reservoir is easily damaged by liquid phase because of the small pores and throats in the formation. Hydraulic fracturing is usually used in this kind of reservoir to improve well productivity; however, sometimes the productivity declines instead of increasing after treatments because of the damage of the water-based stimulation fluids. This paper introduces a production decline case in the HTHP tight gas reservoir in Tarim Basin, Western China, and provides a new solution.

Dixi gas reservoir belongs to the formation of Jurassic Ahe Group, with burial depth of about 5000m. The formation porosity is between 3.0-7.0%, and the permeability is less than 0.1mD. The average DST production rates of three wells in this area were more than 30×104 m3/d. However, the production declined by 40% after completion. Acidizing and proppant fracturing were both conducted to regain their productivities; however, the production rates were reduced even further after the treatments. One of these wells’ daily production rate declined by 78% compared to DST production after use of acid fracturing and hydraulic fracturing. A series of core flow tests were carried out to find out the causes and solutions. The results showed that the retention of fracturing fluid in the formation caused "water blocking damage", which leaded to a significant increase of water saturation and rapid decline of gas phase permeability. This is considered the main cause of well productivity decline. Therefore, minimizing the capillary force in the formation is considered the main approach to remove the damage.

Three series of alternative fracturing fluids were developed and evaluated. The first one is fracturing fluid with methanol. 5%-20% methanol was added to the fracturing fluid to relieve water blocking damage. The results showed that most of the wells fractured by methanol fracturing fluid gained good post-fracturing productivity. Fluorocarbon surfactant fracturing fluid was also developed, in which the concentration of guar gum was reduced to 0.35% to decrease the residual damage. Experimental tests showed that its surface tension was reduced to 0.85mN/m, and the contact angle was increased to 65.47°. Besides, a new nano-scale additive was developed, which can reduce the surface tension of the fracturing fluid from 72.7mN/m to 30.0 mN/m, and increase the contact angle from 38.5° to 126.0°. Thus the capillary force was reduced from 91.78 kPa to -28.44 kPa. Core flow tests under reservoir conditions also showed that the flowback rate of the fracturing fluid with this nano-scale additive was increased by 15% and its displacement pressure was reduced by more than 50% compared with the fracturing fluid without this additive. Besides, the gas-phase permeability of core after treatment with this fracturing fluid was 30% higher than that of normal fracturing fluid.

In this paper, the causes of water blocking damage in an HTHP tight gas reservoir during well stimulation were analyzed. Three sets of alternative fracturing fluids were introduced and their laboratory test results were illustrated. The field application of methanol fracturing fluid was also introduced, which showed a good function of water blocking removal effectiveness. The other two fluids are also expected to obtain effective results in the field.

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