Gas Condensate Reservoir Performance
- F.B. Thomas (Hycal Energy Research Laboratories Ltd.) | D.B. Bennion (Hycal Energy Research Laboratories Ltd.) | G. Andersen (Chevron/Texaco)
- Document ID
- Petroleum Society of Canada
- Journal of Canadian Petroleum Technology
- Publication Date
- July 2009
- Document Type
- Journal Paper
- 18 - 24
- 2009. Petroleum Society of Canada (now Society of Petroleum Engineers)
- 5.3.1 Flow in Porous Media, 1.7.1 Underbalanced Drilling, 5.4.2 Gas Injection Methods, 4.1.2 Separation and Treating, 5.6.9 Production Forecasting, 5.4.3 Gas Cycling, 5.2 Reservoir Fluid Dynamics, 1.7.5 Well Control, 5.5.8 History Matching, 5.2.1 Phase Behavior and PVT Measurements, 4.3.4 Scale, 5.1 Reservoir Characterisation, 5.8.8 Gas-condensate reservoirs, 4.1.5 Processing Equipment, 1.8 Formation Damage, 6.5.3 Waste Management, 1.6.10 Coring, Fishing
- path dependence, bottomhole flowing pressure, gas condensate reservoirs
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Gas condensate reservoirs exhibit complex coupling between phase behaviour, interfacial tension, velocity and pore size distribution. Appropriate characterization of the in situ fluids and relevant flow testing can provide valuable insight into gas condensate reservoir forecasting. The following insights were obtained during the course of this testing:
- The importance of path dependence was shown to be significant when creating equilibrium phases below saturation pressure for use in quantifying phase interference. Differences, due to compositional path, in API gravity of liquids in solution were quantified to be as much as 10 degrees, with molecular weight differences over 110 daltons.
- End-point saturations, such as trapped gas and residual condensate saturation, are sensitive to the level of interfacial tension (IFT). Critical condensate saturation was less sensitive to IFT (pressure).
- The two-phase injection approach and the protocol whereby explicit measurement of relative permeability is performed provide a very thorough gas-condensate reservoir data set, which are amenable for use in simulation and reservoir production forecasting.
This paper discusses performance of gas condensate reservoirs.These reservoirs have a reservoir temperature located between the critical point and the cricondentherm on the reservoir fluid's pressure-temperature diagram. This is the only unique and accurate means of identifying gas condensate reservoirs; any other definition [condensate-gas ratio, C7+ molecular weight (MW) or C7+ API gravity] is specious and ersatz.
In these reservoirs, as the pressure drops, vapour and liquid phases result.Capillary pressure causes phase interference which usually reduces gas productivity. A cross-section of interesting topics that show the complexities of gas-condensate reservoir production have been reported in the literature(1-7). All of the relevant parameters, if well understood, will lead to more accurate evaluation of the amount of hydrocarbon in place, the rate at which the resource can be produced and the optimization strategies as the reservoir matures.
In this paper, retrograde condensate characterization and properties measurement, explicit relative permeability and two-phase dynamic steady-state measurements are discussed. Notwithstanding the very specific nature of this paper in quantifying phase behaviour-fluid flow coupling in the laboratory, it was considered important to provide a short commentary on sampling of gas condensate fluids that form the foundation on which experimental gas condensate testing is built. Extensive treatment of this theme was beyond the scope of the current paper.
Retrograde Condensate Sampling
The bottomhole flowing pressure (PBHF) must be lower than reservoir pressure to induce flow. If the PBHF is less than dew point pressure then liquids drop out in the porous media around the production well. The gas is much more mobile than the condensate and, therefore, the gas-condensate ratios (GCR) exhibited at surface are commonly higher than that of the reservoir fluid.
A further complication of this problem is that the composition of the surface liquid also changes. When the PBHF is above dew point, the MW of the surface liquid is the highest. Figure 1 shows the change in composition incident to decreasing bottomhole pressure.
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