The Canyon Reef reservoir of the Kelly-Snyder Field, Texas, was discovered in 1948. During the early years of production, there was much concern about the very rapid decline in reservoir pressure; however, reservoir engineers were able to show that this was to be expected of a volumetric undersaturated reservoir with an initial pressure of 3112 psig and a bubble-point pressure of only 1725 psig, both at a datum of 4300 ft subsea.13 Their calculations further showed that when the bubble-point pressure is reached, the pressure decline should be much less rapid, and that the reservoir could be produced without pressure maintenance for many years thereafter without prejudice to the pressure maintenance program eventually adopted. In the meantime, with additional pressure drop and production, further reservoir studies could evaluate the potentialities of water influx, gravity drainage, and intrareservoir communication. These, together with laboratory studies on cores to determine recovery efficiencies of oil by depletion and by gas and water displacement, should enable the operators to make a more prudent selection of the pressure maintenance program to be used or should demonstrate that a pressure maintenance program would not be successful.
Although additional and revised data have become available in subsequent years, the following calculations, which were made in 1950 by reservoir engineers, are based on data available in 1950. Table 6.3 gives the basic reservoir data for the Canyon Reef reservoir. Geologic and other evidence indicated that the reservoir was volumetric (i.e., that there would be negligible water influx), so the calculations were based on volumetric behavior. If any water entry should occur, the effect would be to make the calculations more optimistic—that is, there would be more recovery at any reservoir pressure. The reservoir was undersaturated, so the recovery from initial pressure to bubble-point pressure is by liquid expansion and the fractional recovery at the bubble point is
Table 6.3 Reservoir Rock and Fluid Properties for the Canyon Reef Reservoir of the Kelly-Snyder Field, Texas (Courtesy The Oil and Gas Journal)14
Based on an initial content of 1.4235 reservoir barrels or 1.00 STB, this is recovery of 0.0189 STB. Because the solution gas remains at 885 SCF/STB down to 1725 psig, the producing gas-oil ratio and the cumulative produced gas-oil ratio should remain near 885 SCF/STB during this pressure decline.
Below 1725 psig, a free gas phase develops in the reservoir. As long as this gas phase remains immobile, it can neither flow to the wellbores nor migrate upward to develop a gas cap but must remain distributed throughout the reservoir, increasing in size as the pressure declines. Because pressure changes much less rapidly with reservoir voidage for gases than for liquids, the reservoir pressure declines at a much lower rate below the bubble point. It was estimated that the gas in the Canyon Reef reservoir would remain immobile until the gas saturation reached a value near 10% of the pore volume. When the free gas begins to flow, the calculations become quite complex but as long as the free gas is immobile, calculations may be made assuming that the producing gas-oil ratio R at any pressure will equal the solution gas-oil ratio Rso at the pressure, since the only gas that reaches the wellbore is that in solution, the free gas being immobile. Then the average producing (daily) gas-oil ratio between any two pressures p1 and p2 is approximately
and the cumulative gas-oil ratio at any pressure is
On the basis of 1.00 STB of initial oil, the production at bubble-point pressure Npb is 0.0189 STB. The average producing gas-oil ratio between 1725 and 1600 psig will be
The cumulative recovery at 1600 psig Np1 is unknown; however, the cumulative gas-oil ratio Rp may be expressed by Eq. (6.13) as
This value of Rp1 may be placed in Eq. (6.11) together with the PVT values at 1600 psig as
In a similar manner, the recovery at 1400 psig may be calculated, the results being valid only if the gas saturation remains below the critical gas saturation, assumed to be 10% for the present calculations.
When Np stock-tank barrels of oil have been produced from a volumetric undersaturated reservoir and the average reservoir pressure is p, the volume of the remaining oil is (N – Np)Bo. Since the initial pore volume of the reservoir Vp is
and since the oil saturation is the oil volume divided by the pore volume,
On the basis of N = 1.00 STB initially, Np is the fractional recovery RF, or Np/N, and Eq. (5.15) can be written as
where Swi is the connate water, which is assumed to remain constant for volumetric reservoirs. Then at 1600 psig, the oil saturation is
The gas saturation is (1 –So – Swi), or
Sg = 1 – 0.765 – 0.200 = 0.035
Figure 6.4 shows the calculated performance of the Kelly-Snyder Field down to a pressure of 1400 psig. Calculations were not continued beyond this point because the free gas saturation had reached approximately 10%, the estimated critical gas saturation for the reservoir. The graph shows the rapid pressure decline above the bubble point and the predicted flattening below the bubble point. The predictions are in good agreement with the field performance, which is calculated in Table 6.4 using field pressures and production data, and a value of 2.25 MMM STB for the initial oil in place. The producing gas-oil ratio, column 2, increases instead of decreasing, as predicted by the previous theory. This is due to the more rapid depletion of some portions of the reservoir—for example, those drilled first, those of low net productive thickness, and those in the vicinity of the wellbores. For the present predictions, it is pointed out that the previous calculations would not be altered greatly if a constant producing gas-oil ratio of 885 SCF/STB (i.e., the initial dissolved ratio) had been assumed throughout the entire calculation.
Figure 6.4 Material balance calculations and performance, Canyon Reef reservoir, Kelly-Snyder Field.
Table 6.4 Recovery from Kelly-Snyder Canyon Reef Reservoir Based on Production Data and Measured Average Reservoir Pressures, and Assuming an Initial Oil Content of 2.25 MMM STB
The initial oil under a 40-acre unit of the Canyon Reef reservoir for a net formation thickness of 200 feet is
Then, at the average daily well rate of 92 BOPD in 1950, the time to produce 11.35% of the initial oil (i.e., at 1400 psig when the gas saturation is calculated to be near 10%) is
By means of this calculation, the reservoir engineers were able to show that there was no immediate need for a curtailment of production and that there was plenty of time in which to make further reservoir studies and carefully considered plans for the optimum pressure maintenance program. Following comprehensive and exhaustive studies by engineers, the field was unitized in March 1953 and placed under the management of an operating committee. This group proceeded to put into operation a pressure maintenance program consisting of (1) water injection into wells located along the longitudinal axis of the field and (2) shutting in the high gas-oil ratio wells and transferring their allowables to low gas-oil ratio wells. The high-ratio wells were shut in as soon as the field was unitized, and water injection was started in 1954. The operation has gone as planned, and approximately 50% of the initial oil in place has been recovered, in contrast to approximately 25% by primary depletion, an increase of approximately 600 MM STB of recoverable oil.15
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