Investigation of Well Productivity in Gas-Condensate Reservoirs
- Ahmed H. El-Banbi (Schlumberger Holditch-Reservoir Technologies) | W.D. McCain Jr. (Schlumberger Holditch-Reservoir Technologies) | M.E. Semmelbeck (Battlecat Oil & Gas)
- Document ID
- Society of Petroleum Engineers
- SPE/CERI Gas Technology Symposium, 3-5 April, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2000. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 5.7.2 Recovery Factors, 5.5.8 History Matching, 5.2.2 Fluid Modeling, Equations of State, 4.6 Natural Gas, 5.8.8 Gas-condensate reservoirs, 5.2.1 Phase Behavior and PVT Measurements
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The productivity of the wells in a moderately rich gas condensate reservoir was observed to initially decrease rapidly and then increase as the reservoir was depleted. All wells in the field showed the same response. Compositional simulation explained the reasons for these productivity changes.
During early production, a ring of condensate rapidly formed around each wellbore when the near-wellbore pressures decreased below the dew point pressure of the reservoir gas. The saturation of condensate in this ring was considerably higher than the maximum condensate predicted by the PVT laboratory work due to relative permeability effects. This high condensate saturation in the ring severely reduced the effective permeability to gas, thereby reducing gas productivity.
After pressure throughout the reservoir decreased below the dew point condensate formed throughout the reservoir, thus the gas flowing into the ring became leaner causing the condensate saturation in the ring to decrease. This increased the effective permeability of the gas. This caused the gas productivity to increase as was observed in the field.
There were also changes in gas and condensate compositions in the reservoir which affected viscosities and densities of the fluids. These effects also impacted gas productivity.
This work is another step forward in our understanding of the dynamics of condensate buildup around wellbores in gas condensate fields.
Wells in gas condensate reservoirs often experience rapid decline when the near wellbore pressure goes below the dew point pressure. Several investigators1-6 have reported on well productivity of gas condensate reservoirs. Radial compositional simulation models were often used to investigate the problem of productivity loss1-5. These models clearly showed that the loss in productivity was due to liquid drop out around the wellbore. This so called condensate blocking (increase in condensate saturation around the wellbore) reduces the effective permeability to gas and results in rapid decline in well productivity once the near wellbore pressure drops below the dew point. The effect of condensate blocking is more evident in low permeability reservoirs. Barnum et al.7 have noticed that the recovery factor of gas condensate wells is only affected by condensate blocking if the well's kh is less than 1,000 md-ft. For higher quality reservoirs, productivity loss is not very severe.
Figs 1, 2, and 3 show the performance of three different wells producing from the same reservoir. They show the rapid decline common to most gas condensate wells when they go below the dew point. However, they all show approximately stable gas production after the period of initial decline and, more importantly, a subsequent increase in gas production rate. The increase in rate is not due to any improved recovery technique since no fluid injection and no changes in operating conditions have ever taken place in this reservoir.
History Match with a Compositional Simulation Model
We constructed a radial, single-well compositional model to investigate the behavior of one of the wells (well A). The model consisted of one layer with 36 grid blocks in the radial direction. We started with a 0.5 ft. grid block near the well, increased the size logarithmically to gird block 10, and then used uniform grids of 100 ft. afterwards. A 9-component equation of state (EOS) formulation was used. An imbibition gas-oil relative permeability data set in presence of irreducible water was used (Fig. 4). History matching was performed in an attempt to explain the uncommon behavior of the well. The model was constrained by gas rate while reservoir properties were changed to match average reservoir pressure and condensate production rate. Fig. 5 shows the match between actual and simulated condensate production rate. Permeability, porosity, and permeability distribution of the model were altered to achieve this match.
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