### Volumetric Calculations

Volumetric calculations for OOIP (original-oil-in-place) were carried out on each of the sands on a grid-cell by grid-cell basis. Geographix mapping package was used to grid and map sand attributes such as net pay, porosity, and Sw. Each of the sand bodies was gridded with cells sized 165 feet by 165 feet. Standard gridding algorithm inside the mapping package was used to populate the grid cells with attribute values. Grid values were migrated to a spreadsheet environment to facilitate grid-to-grid operations. Figure 9 shows that the permeability value tends to zero as the porosity value gets smaller and smaller. A permeability cut-off of 0.5 md was assumed to be unproducible for Minneola Unit, and thus an effective-porosity grid was generated for each sand by zeroing off grid cells with porosity values less than 4.69%. The OOIP in each grid cell, in each sand body, was calculated by the formula below:

OOIP = (1652 * h *Fe * (1-Sw))/5.615

The OOIP is calculated by this equation is in reservoir barrels (RB), and the other parameters are defined as follows: \$e = effective porosity (fraction), h = pay height, ft, and Sw = water saturation (fraction).

Table 5 summarizes the volumetric calculations and tabulates the pore volume (PV) and OOIP of each of the sands in RBs. The total OOIP of the three sands in the unit plus Hall area is 2.78 MMRB. Laboratory measured data regarding the oil formation volume factor (Bo) was not available.

In solution gas driven reservoirs, gas saturation increases in the reservoir with a lowering of reservoir pressure due to production. Relative flow of gas increases in the reservoir at higher gas saturations, and this results in a continuous rise in the produced gas-oil-ratio (GOR). The peak GOR is at times several times greater than the original solution GOR. Above bubble point pressures, the reservoir rock and remaining fluids expand to fill the void created by the produced fluids. Both rock and reservoir fluids have low compressibility and so a large decrease in pressure is necessary to allow the rock and remaining fluids to expand enough to replace the relatively small amount of oil produced. The result is that above bubble point the pressure decreases rapidly. The producing GOR, recorded at the surface, shows a constant trend till reservoir pressure is at bubble point and thereafter it increases rapidly.

Lease production data was used to plot the GOR profile with time. One of the leases, namely Fager, was found to display constant GOR (Figure 21), around 500 scf/bbl, during the early periods of its production life. This lease contains a single producing well and it was brought online during the initial development of the field, i.e., in January 1984. The constancy of the GOR value indicates that the reservoir pressure around the well was above the bubble point pressure. Due to unavailability of any laboratory-measured GOR value, the solution GOR for the unit plus Hall area was assumed to be 500 scf/STB.

The solution GOR was used to calculate the Bo for the oil. Available well records revealed produced gas analysis where the average specific gravity of the gas was found to be 0.73 (air=1.0). The average reservoir temperature is 116oF and the API gravity of oil is 46. Standard correlations5 were used to calculate Bo, and it was found to be 1.25 RB/STB. The bubble point pressure was calculated by standard correlations5 to be around 1370 psia. Initial reservoir pressure, calculated from DST analysis, was around 1600 psi and given the rapid decline in reservoir pressure (Figure 20), it appears that a gas cap must have formed in the reservoir during the later half of 1983.

The cumulative production from the unit plus Hall area before the onset of the water flood was 0.64 MMSTB of oil and 1760 MMscf of gas. This results in a primary recovery efficiency of 29%, assuming that the representative solution GOR for the reservoir is 500 scf/STB. Generally the recovery efficiency of solution-gas driven reservoirs varies between 15 to 20% of the OOIP, with occasional values varying between 5 to 30%6. The API study on crude oil recovery efficiency7 tabulates average primary recovery efficiency between 15 to 31% (of OOIP) for solution-gas driven sandstone reservoirs.

Production records indicate that after the onset of the waterflood there was no significant gas production from any of the wells. Also by the early part of 1995, the operating fluid levels in the wells was no more than 150 ft, suggesting that the reservoir pressure to be no greater than 100 psi. Thus the remaining oil in the reservoir can be assumed to be gas free by the start of the waterflood. The cumulative oil produced from the unit plus Hall area during the waterflood amounts to 40.8 MSTB and this translates to a secondary recovery efficiency of 3% of the reserves remaining after the primary stage. Thus, a significant amount of the recoverable reserves remain to be recovered in the unit plus Hall area.

Figure 22 shows the production and injection history in the unit plus Hall area during the waterflooding stage. It is apparent from this figure that the volume of water production closely traces that of the total fluid production. Also, the difference between the volumes of total fluid produced and that of water injected diminish with time. This indicates that an increasing amount of the injected water is short-circuiting to the producing wells. Another important observation is that an average production of 378 STB of oil was obtained in the unit plus Hall area during the four months when there was no water injection. Figure 23 summarizes the voidage and fill-up that has taken place due to the water injection. It shows that the volume occupied by free gas in the reservoir is near 400,000 bbls. Thus the total amount of water injected, so far, has not been able to fill-up the voidage created by the fluid production.

The fluid component with the maximum energy in a reservoir is gas, and in case of the unit plus Hall area most of the gas has evolved out of the oil and has been produced. The gas left behind in the reservoir is low-pressure unproducible free gas. Thus at this stage in the reservoir’s life, it is ineffective to pressurize the reservoir by water injection as there is not enough gas left behind to pressurize. So the focus of the water injection should not be to achieve fill-up. The effective mechanism to recover the remaining oil will be to design a water flood that will create and push banks of oil towards the producing wells. Given the size, distribution, and heterogeneity of the sands it appears that two injector wells, namely #3-1 and #7-1, are insufficient to sweep the remaining reserves in an efficient manner. A successful waterflood in this field should take into account different factors including: a) water should be injected in a manner such that each of the three sands are flooded, and b) producing wells should be selected such that their perforations can produce the oil bank built by the nearby injectors. Analyses of the current production-profiles show evidence of connectivity between the sands and of the presence of high permeability streaks within the sands. Detailed characterization studies are required to refine the reservoir model, which can serve as the base for a strategy to effectively sweep the remaining reserves.

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