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Formation damage from condensate banking

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Formation damage in gas/condensate reservoirs can be caused by a buildup of fluids (condensate) around the wellbore. This reduces the relative permeability and therefore gas production. This page discusses condensate banking and how to overcome its effects.

Condensate buildup

As shown in Fig. 1, gas/condensate reservoirs are defined as reservoirs that contain hydrocarbon mixtures that on pressure depletion cross the dewpoint line. In such instances as when the bottomhole pressure is reduced during production, the dewpoint pressure of the gas is reached in the near-wellbore region. This results in the formation of liquid hydrocarbons near the wellbore and in the reservoir. As the liquid hydrocarbon saturation in the near-wellbore region increases, the gas relative permeability is decreased, resulting in significant declines in well productivity. [1][2] An example of this is shown by the data in Fig. 2. Here, a substantial reduction in well productivity is obtained as the average reservoir pressure declines below the dewpoint for a well in the Arun gas field. This mechanism of formation damage is related primarily to changes in fluid saturation in the near-wellbore region, resulting in decreases in gas relative permeability.

The buildup of the condensate bank and its consequences on well productivity have been well studied in the literature. [4][5][6][7][8][3][9][10][11][12][13]). Early predictions of productivity loss because of condensate dropout indicated that a loss in PI by a factor of 5 to 8 would be expected because of liquid buildup. [6][7][8] However, the decline in productivity index (PI) observed in many of the fields is much smaller (a factor of 2 to 4). Further investigation of this problem indicated that the high gas flow rates in the near-wellbore region can result in stripping out of the liquid hydrocarbon phase in regions around the wellbore. This stripping-out effect has been quantified through capillary-number-dependent models for relative permeability of the gas phase. [5][13] With this phenomenon properly accounted for, good agreement with field observations is obtained (Fig. 2).

In addition to liquid dropout, several other important phenomena can play an important role in determining well productivity and need to be carefully evaluated. Because of the high flow rates of gas in the near-wellbore region, non-Darcy effects may be significant and may need to be accounted for. [3][9][10][11] The combination of non-Darcy flow, capillary-number-dependent relative permeability, and phase behavior makes the problem rather complex, and numerical simulations are needed to fully capture all the physics of the problem. Clearly distinguishing the effects of liquid dropout from non-Darcy effects from production performance and pressure-transient tests can be challenging and may require compositional numerical models. Such models are widely available and have been used in estimating gas-well productivity, including condensate dropout.

Reducing condensate buildup

The most direct method of reducing condensate buildup is to reduce the drawdown so that the bottomhole pressure remains above the dewpoint. In cases when this is not desirable, the impact of condensate formation can be reduced by increasing the inflow area and achieving linear flow rather than radial flow into the wellbore. This minimizes the impact of the reduced gas permeability in the near-wellbore region. Both of these benefits can be achieved by hydraulic fracturing.

Hydraulic fracture stimulation is the most common method used to remedy condensate buildup problems. The creation of a fracture results in a significant decrease in the drawdown needed to produce the well. In addition, buildup of a liquid hydrocarbon phase on the faces of the fracture does not affect well productivity as significantly as in radial flow around the wellbore. Additional details of this are available elsewhere. [12]

Recently, the use of solvents and surfactants such as methanol has been suggested as a way to stimulate gas/condensate wells in which hydraulic fracturing is not the preferred option. [14][15] The use of methanol results in removal of the condensate and water banks around a wellbore. This allows gas flow to be unimpeded through the near-wellbore region, resulting in smaller drawdown and slower accumulation of condensate. Within certain ranges of temperature and pressure, the presence of a residual methanol phase in the near-wellbore region can also result in the inhibition of condensate formation for a period of time.


  1. Afidick, D., Kaczorowski, N.J., and Bette, S. 1994. Production Performance of a Retrograde Gas Reservoir: A Case Study of the Arun Field. Presented at the SPE Asia Pacific Oil and Gas Conference, Melbourne, Australia, 7-10 November 1994. SPE-28749-MS.
  2. Barnum, R.S., Brinkman, F.P., Richardson, T.W. et al. 1995. Gas Condensate Reservoir Behaviour: Productivity and Recovery Reduction Due to Condensation. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October 1995. SPE-30767-MS.
  3. 3.0 3.1 3.2 3.3 Narayanaswamy, G., Pope, G.A., Sharma, M.M. et al. 1999. Predicting Gas Condensate Well Productivity Using Capillary Number and Non-Darcy Effects. Presented at the SPE Reservoir Simulation Symposium, Houston, Texas, 14-17 February 1999. SPE-51910-MS.
  4. Boom, W., Wit, K., Zeelenberg, J.P.W. et al. 1996. On the Use of Model Experiments for Assessing Improved Gas-Condensate Mobility Under Near-Wellbore Flow Conditions. Presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 6–9 October. SPE-36714-MS.
  5. 5.0 5.1 Boom, W., Wit, K., Schulte, A.M. et al. 1995. Experimental Evidence for Improved Condensate Mobility at Near-wellbore Flow Conditions. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October 1995. SPE-30766-MS.
  6. 6.0 6.1 Asar, H. and Handy, L.L. 1988. Influence of Interfacial Tension on Gas/Oil Relative Permeability in a Gas-Condensate System. SPE Res Eng 3 (1): 257-264. SPE-11740-PA.
  7. 7.0 7.1 Hartman, K.J. and Cullick, A.S. 1994. Oil recovery by gas displacement at low interfacial tension. J. Pet. Sci. Eng. 10 (3): 197-210.
  8. 8.0 8.1 Henderson, G.D., Danesh, A., Tehrani, D.H. et al. 1998. Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method. SPE Res Eval & Eng 1 (2): 134–140. SPE-30770-PA.
  9. 9.0 9.1 Wang, X. and K.K., M. 1999. Multiphase Non-Darcy Flow in Gas-Condensate Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3–6 October. SPE-56486-MS.
  10. 10.0 10.1 Coles, M.E. and Hartman, K.J. 1998. Non-Darcy Measurements in Dry Core and the Effect of Immobile Liquid. Presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, 15-18 March 1998. SPE-39977-MS.
  11. 11.0 11.1 Narayanaswamy, G., Sharma, M.M., and Pope, G.A. 1999. Effect of Heterogeneity on the Non-Darcy Flow Coefficient. SPE Res Eval & Eng 2 (3): 296-302. SPE-56881-PA.
  12. 12.0 12.1 Kumar, R. 2000. Productivity Improvement in Gas Condensate Reservoirs Through Fracturing. MS thesis, University of Texas at Austin.
  13. 13.0 13.1 Pope, G.A., Wu, W., Narayanaswamy, G. et al. 2000. Modeling Relative Permeability Effects in Gas-Condensate Reservoirs With a New Trapping Model. SPE Res Eval & Eng 3 (2): 141–178. SPE-62497-PA.
  14. Du, L., Walker, G.J., Pope, G.A. et al. 2000. Use of Solvents to Improve the Productivity of Gas Condensate Wells. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 1–4 October. SPE-62935-MS.
  15. Al-Anazi, H.A., Pope, G.A., Sharma, M.M. et al. 2002. Laboratory Measurements of Condensate Blocking and Treatment for Both Low and High Permeability Rocks. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September-2 October 2002. SPE-77546-MS.

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See also

Formation damage

PEH:Formation Damage