Comparative Well-Test Behaviours in Low-Permeability Lean, Medium-rich, and Rich Gas-Condensate Reservoirs
- Thabo Clifford Kgogo (PetroSA) | Alain C. Gringarten (Imperial College)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 19-22 September, Florence, Italy
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.4.2 Gas Injection Methods, 4.2 Pipelines, Flowlines and Risers, 4.1.4 Gas Processing, 5.1.1 Exploration, Development, Structural Geology, 4.6 Natural Gas, 1.10 Drilling Equipment, 5.3 Reservoir Fluid Dynamics, 5.2.2 Fluid Modeling, Equations of State, 5.8.8 Gas-condensate reservoirs, 5.2.1 Phase Behavior and PVT Measurements, 5.1 Reservoir Characterisation, 2.2.2 Perforating, 5.6.4 Drillstem/Well Testing, 5.3.2 Multiphase Flow, 5.2 Reservoir Fluid Dynamics, 5.5.11 Formation Testing (e.g., Wireline, LWD)
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Large condensate banks develop around producing wells in gas-condensate reservoirs when pressure drops below the dew point pressure, inducing severe losses of productivity. Actual well test behaviours depend on fluid composition, formation permeability and production rates.
Several publications have presented well test behaviours in high permeability lean and rich gas-condensate reservoirs. This paper investigates well test behaviours below the dew point pressure in low permeability lean, medium-rich and rich gascondensate reservoirs using 3-D compositional simulation. It is shown that during a drawdown below the dew point pressure, medium-rich to rich gas-condensate fluids in the condensate bank change to near critical fluid near the wellbore. If such a drawdown is followed by a shut-in where the pressure builds up above the saturation pressure, the oil revaporizes completely and the fluid in the wellbore vicinity becomes single-phase gas again. This does not occur in lean gas reservoirs, where the condensate saturations at the end of a drawdown and in the subsequent build up are very similar. Another difference is that lean and mediumrich gas-condensate fluids yield three mobility zones on a derivative plot corresponding to: (1) the original gas in place away from the well where the pressure is above the dew point pressure; (2) the condensate bank closer to the well; and (3) capillary number effects in the immediate vicinity of the well. By contrast, only two mobility zones are created in the case of rich gas-condensate fluids (capillary number effects are not seen in practice).
The understanding of pressure behaviour in low permeability, gas-condensate reservoirs developed in this paper was applied to actual well test data from a South Coast Gas field located offshore South Africa and helped optimize well performance and reservoir management strategies in that field.
Introduction and background
Gas-condensate reservoirs exhibit complex flow behaviours due to the build up of condensate banks around the wells when the bottom-hole pressure drops below the dew point pressure. Condensate banks create a blockage which rapidly lowers well productivity by a factor of two to four (Afidick et al., 1994; Barnum et al., 1995).
Medium-rich to rich gas-condensate reservoirs have attracted much interest as they enhance revenue generation and yield profits that make gas projects attractive. Takeda et al., (1997) showed that rich gas reservoirs achieve considerably higher liquid saturations than lean gas reservoirs and therefore suffer much higher productivity losses. They also indicated that bottomhole pressure decreases more rapidly and condensate drop-out is higher around the well in a low permeability reservoir than a high permeability reservoir for the same production schedule. The latter point had been stressed previously by Eilerts et al., (1965) who showed that the higher the formation permeability, the lower the reduction of gas recovery. Barnum et al., (1995) suggested that the reduction of gas production is more pronounced in reservoirs with kh less than 1000 mD.ft. Clearly, low-permeability, medium-rich to rich gas-condensate reservoirs present a production challenge because of higher drawdowns creating significant liquid drop-out in the reservoir and lower achievable gas rates.
Phase Behaviour in Gas-condensate Reservoirs
Reservoir fluids are characterized as dry gas, wet gas, gas-condensate, near-critical fluid, volatile oil or black oil. In near critical fluids, characterised by a reservoir temperature close to the critical temperature, it is difficult to differentiate between gas and liquid phases since the corresponding physical properties such as density and viscosity are similar near the critical point.
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