This indicates that by increasing the solvent amount, the solvency power is improved. The oil recovery and ash reduction for the same ratio are better than that obtained for solvent to oil ratio of 3:1 and 2:1. 4.1 indicate that the maximum ash reduction is achieved for solvent to oil ratio of 4:1. The results of the investigation, Table 4.3 and Fig. Depletion-drive recoveries are often between 15% and 30% of the original oil-in-place.įig. This liquid recovery at the surface can equal or exceed the volume of stock-tank oil produced from the reservoir liquid phase. The produced gas can yield a substantial volume of hydrocarbon liquids in the processing equipment. This results in relatively high gas saturation, high producing GORs, and low-to-moderate production of reservoir oil. The error increases for increasing oil volatility.Ĭonsequently, depletion performance of volatile oil reservoirs below bubble point is strongly influenced by the rapid shrinkage of oil and by the large amounts of gas evolved. Conventional material balances with standard laboratory PVT (black oil) data underestimate oil recovery. Thus, performance predictions differ from those discussed for black oils mainly because of the need to account for liquid recovery from the produced gas. This causes relatively high GORs at the wellhead. Also, volatile oils evolve gas and develop free-gas saturation in the reservoir more rapidly than normal black oils as pressure declines below the bubble point. This is in contrast to black oils for which little error is introduced by the assumption that there is negligible hydrocarbon liquid recovery from produced gas. As the reservoir pressure drops below the bubble point pressure, the evolved solution gas liberated in the reservoir contains enough heavy components to yield appreciable condensate dropout at the separators that is combined with the stock-tank oil. This type of crude oil system is characterized by significant hydrocarbon liquid recovery from their produced reservoir gases. This situation is more complex when dealing with volatile oils. Surface gas released from the reservoir oil has the same properties as the reservoir gas. Properties of stock-tank oil in terms of its API gravity and surface gas do not change with depletion pressure. Reservoir oil consists of two surface “components” stock-tank oil and total surface separator gas. Reservoir gas does not yield liquid when brought to the surface. However, in formulating the material balance equation, the following assumptions were made when using the black oil PVT data: (1) Whitson and Brule (2000) point out that the above three properties constitute the classical (black oil) PVT data required for various type of applications of the MBE. These correlations are dependent on primary separator conditions in addition to the usual correlations input parameters. Correlations are used to estimate the stock-tank GOR. Therefore, the value of the stock-tank GOR is not usually available. In the majority of oil field operations, the gas produced from the stock-tank (and sometimes the low-pressure separator) is vented or sent to the flare. The correct PVT correlations input is the total GOR (and not the separator GOR). In addition, taking a 3 or 4-month moving average for the data reduces the scattering in GOR data and obtains a more representative average initial GOR. In this example, considerable variation in GOR data occurred in 2005 and after, due to changes in wells completion and poor maintenance of gas meters.Ĭonsideration of the entire field GOR rather than individual wells GOR is important for selecting an appropriate value for use in PVT correlations. The GOR data generally show fluctuations. GOR starts to increase and reaches 1000 scf/STB. 7.8 shows that the field producing GOR is a constant value (around 580 scf/STB) for some time until cumulative oil production has reached 0.5 MMSTB.
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