Waterflooding of Gas Condensate Reservoirs
- T.P. Fishlock (AEA Technology) | C.J. Probert (AEA Technology)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1996
- Document Type
- Journal Paper
- 245 - 251
- 1996. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 1.2.3 Rock properties, 4.3.4 Scale, 5.5 Reservoir Simulation, 5.8.8 Gas-condensate reservoirs, 5.2.1 Phase Behavior and PVT Measurements, 6.5.2 Water use, produced water discharge and disposal, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 5.7.2 Recovery Factors, 5.4.1 Waterflooding
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Gas-condensate reservoirs are usually produced by primary depletion. This technique is normally an efficient means of producing the gaseous hydrocarbon components but can be very inefficient in producing the more valuable liquid components which are left in the reservoir in a condensed liquid phase. The recovery efficiency of the liquid components decreases with increasing richness of the gas condensate, making for a large IOR target in some reservoirs.
The usual approach to improving liquids recovery is to recycle produced gas through the reservoir. However, this technique may not be economically attractive when there is the possibility of immediate gas sales because of the discounting applied to the gas value when sales are delayed.
An alternative means of improving liquid recovery is to keep the reservoir pressure above the dew-point for a period by injecting water. Depending on reservoir characteristics, water injection may be continued throughout field life or the reservoir may be pressure depleted after a period of injection. Special relative permeability data, describing the mobilisation of waterflood trapped gas by expansion, are necessary for the latter case.
This paper reports a simulation study to quantify the potential benefits of the waterflood technique using simple reservoir models. For a fluid with a condensate to gas ratio of 180 STB/MMscf, total hydrocarbon recovery was optimised by injecting 0.25 hydrocarbon pore volumes of water before pressure depletion. This increased the recovery efficiency of both the liquid and gaseous components. raising the total hydrocarbon recovery by 10% of the hydrocarbon mass initially present in the reservoir. For a richer, near-critical fluid with a condensate to gas ratio of 300 STB/MMscf, continued water injection gave the optimum total recovery which was 21% of initial mass higher than for primary depletion. This improvement was achieved by greatly increasing the liquids recovery at the expense of a smaller reduction in the gas recovery.
The results of this paper suggest that waterflooding of gas condensate reservoirs might be a valuable IOR technique.
Gas condensate reservoirs are usually produced by primary depletion. This technique is normally an efficient means of producing the gaseous hydrocarbon components but can be very inefficient in producing the more valuable liquid components which are left in the reservoir in a condensed liquid phase (oil). The recovery efficiency of the liquid components decreases with increasing richness of the gas condensate, making for a large IOR target in some reservoirs.
One possibility for increasing the recovery of these liquid components is to inject water, maintaining pressure above the dewpoint thus preventing condensation within the bulk of the reservoir. Full pressure maintenance in this manner suffers from the disadvantage that gas is trapped at high pressure at the end of field life, reducing the gas recovery efficiency. Therefore, there is an optimum period of water injection, dependent on the gas relative permeability curve, which maximises the hydrocarbon recovery when the reservoir is finally blown down to the abandonment pressure. Since these studies were performed. additional laboratory data have been obtained on gas flow in three-phase gas/condensate/water systems which show that previous work needs to be revised. Also, the work needed to be extended to cover richer gas condensates.
This report describes further work on gas condensate reservoir behaviour. This study uses two reservoir fluids with CGRs (condensate to gas ratios) of 180 STB/MMscf and 300 STB/MMscf. These fluids are more representative of some of the richer condensates now being considered for development in the UKCS. The same simulation model has been used as in previous studies, but with an improved treatment of the relative permeabilities.
Firstly, we examine the saturation histories which may be encountered in waterflooding gas condensates and summarise the relevant laboratory data on gas relative permeability. Secondly, we describe the two reservoir fluids used.
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