In the 21st century, the global gas demand will be met only by extensive production of unconventional gas (shale and tight sand gas, deep gas, basin concentrated gas accumulation, etc.). All such gas-bearing formations are characterized, however, by extremely low, usually micro Darcy range permeability. Unfortunately, the operators of such reservoirs face with difficulties when routine drilling, well completion, fracturing, and production technologies are used. One source of the problems can be traced back to use of water-base fluids. Therefore, the laboratory studies aimed at elucidating the reasons why water-based fluids are harmful and seriously jeopardize the gas production from such reservoirs.

The water induced formation damage is illustrated in a porous media having 0.001–0.1 mD permeability and obtained from a tight sand gas formation. Its pore structure was analyzed by HP Hg porosimetry and the wettability was determined by digital image analysis. The spontaneous imbibition was tested with standard method. Surface tension of water was determined by automatic ring method. The critical Pc needed to mobilize water was calculated as a function of pore size distribution.

Using the relevant data (pore size distribution, wettability and surface tension) the calculated Pc was in range of 40–75 bar for cores obtained from medium depth (3600 m); meanwhile it was extremely high, 500–600 bar for cores derived from deeper layers (>6000 m). Based on these data it was concluded that the native water saturation should be high (>70%) and immobile in similar formations and because of the high imbibition rate the water behaves as a potential blocking phase in the cores. The mentioned factors seriously influence both the resource/reserve assessment and the production efficiency. Since the water may induce formation damage hard to control, application of water free fluids is recommended in any phase of field operation at unconventional gas reservoirs.

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