Chemical Treatment To Mitigate Condensate and Water Blocking in Gas Wells in Carbonate Reservoirs
- Mohabbat Ahmadi (The University of Texas at Austin) | Mukul M. Sharma (The University of Texas at Austin) | Gary Pope (The University of Texas at Austin) | David E. Torres (The University of Texas at Austin) | Corey A. McCulley (The University of Texas at Austin) | Harold Linnemeyer (The University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- February 2011
- Document Type
- Journal Paper
- 67 - 74
- 2011. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 1.8 Formation Damage, 5.2.1 Phase Behavior and PVT Measurements, 5.8.7 Carbonate Reservoir, 1.6.9 Coring, Fishing
- Application of Chemicals in Oil and Gas Industry
- 1 in the last 30 days
- 1,005 since 2007
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Many gas wells suffer a loss in productivity because of liquid accumulation in the near-wellbore region. Chemical stimulation may be used as a remedy by altering the wettability to nonliquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well's deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray photoelectron spectroscopy (XPS) measurements and drop-imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests.
An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We acquired measured relative permeability values in Texas cream limestone (TCL) cores from high-pressure/high-temperature (HP/HT) coreflood experiments before and after treatment. Measurements were made using a pseudosteady-state method with a synthetic gas/condensate mixture. To enhance the durability of the treatment, a special amine primer is introduced. The gas relative permeability increased considerably (approximately 80%) after the treatment compared to that before treatment. This increase remained substantial, greater than 60% after injection of more than 1,000 pore volumes (PV) of gas/condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PV of brine and increasing the temperature in the treated core from 175 to 275°F.
The chemical treatment developed in this research can be applied to increase well deliverability of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.
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