Phenomenological Modeling of Critical Condensate Saturation and Relative Permeabilities in Gas/Condensate Systems
- Kewen Li (Reservoir Engineering Research Inst.) | Abbas Firoozabadi (Reservoir Engineering Research Inst.)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- June 2000
- Document Type
- Journal Paper
- 138 - 147
- 2000. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements, 4.3.4 Scale, 1.6.9 Coring, Fishing, 5.8.8 Gas-condensate reservoirs, 5.3.1 Flow in Porous Media, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating, 5.4.2 Gas Injection Methods, 5.3.2 Multiphase Flow, 5.5 Reservoir Simulation
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The effects of gravity, viscous forces, interfacial tension, and wettability on the critical condensate saturation and relative permeability of gas condensate systems are studied using a phenomenological simple network model. The results from the simple model show that wettability significantly affects both critical condensate saturation and relative permeability. Relative permeability at some saturations may increase significantly as the contact angle is altered from 0° (strongly liquid-wet) to 85° (intermediately gas-wet). The results suggest that gas well deliverability in condensate reservoirs can be enhanced by wettability alteration near the wellbore.
Much attention has been paid to the study of in-situ liquid formation and fluid flow mechanisms in gas condensate systems in recent years. When gas condensate reservoirs are developed by pressure depletion, gas well deliverability is affected by the amount and the distribution of the condensate formed around the wellbore. Understanding of the parameters that affect the distribution and the amount of condensate saturation Sc in the wellbore and the effect of these parameters on gas and liquid flow are important in the development of the methods for increased gas deliverability.
There are numerous field examples of gas condensate reservoirs that experience a sharp drop in gas well deliverability at high pressures due to condensation near the wellbore.1-3 There are examples that show that the condensation may even kill gas production.2 The sharp reduction in gas deliverability may be due to the shape of the gas phase relative permeability (krg); the mechanisms of gas productivity impairment are not yet clear. Two main parameters affect condensate recovery and gas well deliverability. These two parameters are critical condensate saturation (Scc which affects liquid recovery) and gas phase relative permeability (krg which affects well deliverability).
Various authors4-9 have measured Scc and a wide range of observations has been reported. The measured values of Scc are generally in the range of 10 to 50%. Gravier et al.4 measured Scc in low-permeability carbonate cores with permeability in the range of 0.5 to 40 md and interfacial tension (?) variations from 0.5 to 1.5 dyn/cm. Scc varied from 24.5 to 50.5% with an average of 35.0%. These measurements were conducted in the presence of connate water. Morel et al.9 reported a critical condensate saturation of less than 1% for ?=0.05 dyn/cm and connate water saturation of 20%. The critical condensate saturation was measured in a vertical dolomite core. The measured Scc is apparently related to various effects including gravity and interfacial tension.
Some authors have accounted for the effect of gravity by conducting flow experiments both in horizontal and vertical directions. Danesh et al.10 studied the effect of gravity on Scc in water-wet micromodels and sandstone cores. They found that Scc in a vertical core was lower than that in a horizontal core; their tests showed that gravity reduced the critical condensate saturation. These authors also examined the dependence of critical condensate saturation on ?. As expected, Scc increases with an increase in ?. Ali et al.11 observed an improved condensate recovery of 17.2% in a vertical gas injection compared with that in a horizontal injection. Their experiments were conducted with a high interfacial tension for gas condensates (?=0.92 dyn/cm). Sandstone cores and a synthetic six-component fluid were used by these authors. When ? was decreased to 0.04 dyn/cm, condensate recovery improved to 27.5% with vertical injection. Henderson et al.12 also reported a significant reduction of the critical condensate saturation in long vertical core samples in comparison with those in horizontal cores. Munkerud,6 however, did not find a significant difference in condensate recovery and saturation between horizontal and vertical pressure depletion. He used Berea cores and a synthetic six-component fluid.
A number of authors have studied gas phase relative permeability (krg ) of gas condensate systems. Gravier et al.4 found an abrupt decrease in krg at saturation close to Scc Chen et al.5 measured krg at reservoir pressures with reservoir rock and reservoir fluids from two North Sea gas condensate reservoirs (reservoirs A and B). The interfacial tension ? varied from 0.01 to 0.42 dyn/cm. The results showed that krg reduced about 10-fold due to condensation when Sc reached 20% for the core and fluid from reservoir A. Reduction of krg with the increase of Sc for the core and fluid from reservoir B is less pronounced but an abrupt decrease of krg at the saturation close to Scc was also observed. Chen et al.5 showed that krg is rate dependent; it increases with the increase of the flow rate. Henderson et al.13 measured gas condensate relative permeabilities using a long Berea core and a five-component synthetic gas condensate fluid; ? varied from 0.05 to 0.40 dyn/cm. They found that the relative permeabilities of both gas and liquid phases decreased with the increase of ? and increased with the increase of the flow rate. Gas relative permeability was more sensitive to ? and flow rate than liquid relative permeability. The results from the work of Munkerud6 and of Haniff and Ali14 differ from the other authors. They did not observe the abrupt decrease of krg.
The brief review above points out that there are many unresolved issues in the study of critical condensate saturation and gas condensate relative permeability. The sharp decrease in gas relative permeability at saturation close to Scc that was observed experimentally has not yet been studied theoretically. The dependence of Scc, krg, and krc on interfacial tension, viscous force, and gravity are not clear from the experimental data. The question remains how to measure Scc, krg, and krc in the laboratory and how to scale them to field conditions. The conclusions drawn from the experimental results are sometimes not consistent. A theoretical understanding of the effect of ?, gravity, viscous force, and wettability on Scc, krg, and krc provides insight into the recovery of liquid condensate from rich gas condensate reservoirs, and gas well deliverability from both rich and lean gas condensate reservoirs.
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