The laboratory test on the retrograde condensate fluid in Example 5.3 is itself a material balance study of the volumetric performance of the reservoir from which the sample was taken. The application of the basic data and the calculated data of Example 5.3 to a volumetric reservoir is straightforward. For example, suppose the reservoir had produced 12.05 MMM SCF of gross well fluid when the average reservoir pressure declined from 2960 psia initial to 2500 psia. According to Table 5.4, the recovery at 2500 psia under volumetric depletion is 15.2% of the initial gross gas in place, and therefore the initial gross gas in place is
Because Table 5.4 shows a recovery of 80.4% down to an abandonment pressure of 500 psia, the initial recoverable gross gas or the initial reserve is
Initial reserve = 79.28 × 109 × 0.804 = 63.74 MMM SCF
Since 12.05MMM SCF has already been recovered, the reserve at 2500 psia is
Reserve at 2500 psia = 63.74 – 12.05 = 51.69 MMM SCF
The accuracy of these calculations depends, among other things, on the sampling accuracy and the degree of which the laboratory test represents the volumetric performance. Generally there are pressure gradients throughout a reservoir to indicate that the various portions of the reservoir are in varying stages of depletion. This is due to greater withdrawals in some portions and/or to lower reserves in some portions because of lower porosities and/or lower net productive thicknesses. As a consequence, the gas-oil ratios of the wells differ, and the average composition of the total reservoir production at any prevailing average reservoir pressure does not exactly equal the composition of the total cell production at the same pressure.
Although the gross gas production history of a volumetric reservoir follows the laboratory tests more or less closely, the division of the production into residue gas and liquid follows with less accuracy. This is due to the differences in the stage of depletion of various portions of the reservoir, as explained in the preceding paragraph, and also to the differences between the calculated liquid recoveries in the laboratory tests and the actual efficiency of separators in recovering liquid from the fluid in the field.
The previous remarks apply only to volumetric single-phase gas-condensate reservoirs. Unfortunately, most retrograde gas-condensate reservoirs that have been discovered are initially at their dew-point pressures rather than above them. This indicates the presence of an oil zone in contact with the gas-condensate cap. The oil zone may be negligibly small or commensurate with the size of the cap, or it may be much larger. The presence of a small oil zone affects the accuracy of the calculations based on the single-phase study and is more serious for a larger oil zone. When the oil zone is of a size at all commensurate with the gas cap, the two must be treated together as a two-phase reservoir.
Many gas-condensate reservoirs are produced under a partial or total water drive. When the reservoir pressure stabilizes or stops declining, as occurs in many reservoirs, recovery depends on the value of the pressure at stabilization and the efficiency with which the invading water displaces the gas phase from the rock. The liquid recovery is lower for the greater retrograde condensation because the retrograde liquid is generally immobile and is trapped together with some gas behind the invading waterfront. This situation is aggravated by permeability variations because the wells become “drowned” and are forced off production before the less permeable strata are depleted. In many cases, the recovery by water drive is less than by volumetric performance, as explained.
When an oil zone is absent or negligible, the material balance Eq. (4.13) may be applied to retrograde reservoirs under both volumetric and water-drive performance, just as for the single-phase (nonretrograde) gas reservoirs for which it was developed:
This equation may be used to find either the water influx, We, or the initial gas in place, G. The equation contains the gas deviation factor z at the lower pressure. It is included in the gas volume factor Bg in Eq. (4.13). Because this deviation factor applies to the gas-condensate fluid remaining in the reservoir, when the pressure is below the dew-point pressure in retrograde reservoirs, it is a two-phase gas deviation factor. The actual volume in Eq. (2.7) includes the volume of both the gas and liquid phases, and the ideal volume is calculated from the total moles of gas and liquid, assuming ideal gas behavior. For volumetric performance, this two-phase deviation factor may be obtained from such laboratory data as obtained in Example 5.3. For example, from the data of Table 5.5, the cumulative gross gas production down to 2000 psia is 485.3M SCF/ac-ft out of an initial content of 1580 M SCF/ac-ft. Since the initial hydrocarbon pore volume is 7623 ft3/ac-ft (Example 5.3), the two-phase volume factor for the fluid remaining in the reservoir at 2000 psia and 195°F as calculated using the gas law is
Table 5.5 Two-Phase and Single-Phase Gas Deviation Factors for the Retrograde Gas-Condensate Fluid of Example 5.3
Table 5.5 gives the two-phase gas deviation factors for the fluid remaining in the reservoir at pressures down to 500 psia, calculated as before for the gas-condensate fluid of Example 5.3. These data are not strictly applicable when there is some water influx because they are based on cell performance in which vapor equilibrium is maintained between all the gas and liquid remaining in the cell, whereas in the reservoir, some of the gas and retrograde liquids are enveloped by the invading water and are prevented from entering into equilibrium with the hydrocarbons in the rest of the reservoir. The deviation factors in Table 5.5, column 4, may be used with volumetric reservoirs and, with some reduction in accuracy, with water-drive reservoirs.
When laboratory data such as those given in Example 5.3 have not been obtained, the gas deviation factors of the initial reservoir gas may be used to approximate those of the remaining reservoir fluid. These are best measured in the laboratory but may be estimated from the initial gas gravity or well-stream composition using the pseudoreduced correlations. Although the measured deviation factors for the initial gas of Example 5.3 are not available, it is believed that they are closer to the two-phase factors in column 4 than those given in column 5 of Table 5.5, which are calculated using the pseudoreduced correlations, since the latter method presumes single-phase gases. The deviation factors of the produced gas phase are given in column 6 for comparison.
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