How reservoir property variations may effect Frio hydrocarbon volumes

Oct. 15, 2001
The question often arises as to what effect, if any, do variations in common reservoir properties have on the amount of hydrocarbon reserves present.

The question often arises as to what effect, if any, do variations in common reservoir properties have on the amount of hydrocarbon reserves present.

As the values of these properties increase or decrease, do such changes effect the amounts of reserves present?

These reservoir properties include depth of production, porosity, permeability, oil-column thickness, API gravity, reservoir temperature, reservoir initial pressure, and water saturation. Unfortunately the number of proved acres for each reservoir often has not been published.

It must be recognized that any conclusions reached may not apply directly to reservoirs in other areas but might provide ideas that can be applied elsewhere.

Gulf Coast Frio fields

Data from 62 reservoirs in 44 fields producing from the Frio formation on the Texas Gulf Coast were examined.1

The Frio formation, alternating layers of sandstone and shale of Oligocene age, has been one of the major producers in the onshore Gulf Coast. Recoverable reserves total 2.7 billion bbl in reservoirs containing from 6 million to 337 million bbl with an average reserve size of 44.6 million bbl.

The number of reservoirs ranges from one to six in a single field and from one to 17 reservoirs at varying intervals of different properties. Additional or smaller fields may have been found in the Frio formation, but data about the properties of these fields have not been available. Because of the possibility of outside influences, Frio reservoirs related to or connected with known salt domes were not included.

Average values for different properties (totals for different property intervals divided by the number of reservoirs at that interval) were used in most of the survey, as it is difficult to compare information about 17 reservoirs at one interval with information about one reservoir at the same interval without some method of averaging.

Variations in data may occur with some averages where only one reservoir is present. Trend lines were included as these may be more helpful in determining if total values are increasing or decreasing.

Reservoirs by reserves

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In Fig. 1 the recoverable reserves were separated into 14 intervals of 25 million bbl intervals ranging from zero to 350 million bbl. Fig. 1a shows the number of reservoirs included in each of the 14 intervals, 1b shows the average reserves in million barrels by each of the 14 intervals, and 1c shows the percent of total reserves in each of the 14 intervals.

Thirty-four reservoirs, 55% of the total, were found in the 0-25 million bbl interval with 19% of the total reserves. The largest average of 337 million bbl was found in one reservoir in the 325-350 million bbl interval.

Only one reservoir is found in each of the reserve intervals of 100-125 million bbl, 250-275 million bbl, and 325-350 million bbl. No reserves were found in four reservoirs in the 150-250 million bbl intervals or the two reservoirs in the 275-325 million bbl intervals.

Other parameters

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Fig. 2a shows the average depth of production by the 14 reserve intervals, 2b shows the average porosity by the reserve intervals, and 2c shows the average permeability by reserve intervals.

Depths of production ranged from 3,800 to 10,000 ft and averaged 5,774 ft, with the deepest average depth of 6,100 ft in the six reservoirs in the 50-75 million bbl range.

Porosity ranged from 20% to 38% with an overall average of 28%. Highest average porosity by reserve interval size was 32% for four intervals: 100-125 million bbl, 125-149 million bbl, 250-275 million bbl, and 325-350 million bbl.

Permeability ranged from 161 to 4,500 md and averaged 976 md. The highest average permeability of 2,136 md was in the 325-350 million bbl interval.

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Fig. 3a shows the average oil-column thickness, 3b the average reservoir pressure, and 3c the reservoir temperature, all by the 14 reserve intervals. Thickness of oil columns range from 10 ft to 570 ft and averaged 73 ft. The thickest average oil-column was 200 ft in the 250-275 million bbl size interval.

Reservoir pressures ranged from 1,604 psi to 4,100 psi, averaged 2,622 psi, with the highest average of 3,317 psi at a reserve interval of 50-75 million bbl. Reservoir temperatures ranged from 130° to 233° F. and averaged 169°, with the highest average temperature of 182° at the 75-100 million bbl interval.

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Fig. 4a shows the API gravities, 4b the gas-oil ratios, and 4c the water saturation, by various reserve intervals. API gravities ranged from 23 to 47° and averaged 34°, with the highest average of 36° in both the 0-25 and 250-275 million bbl intervals.

Gas-oil ratios ranged from 105 to 7,008 and averaged 803, with the highest average GOR of 1,991 in the 75-100 million bbl interval.

Water saturation ranged from 13% to 45% and averaged 30%, with the highest average in 33% in both the 25-50 and 100-125 million bbl intervals.

The results show the tendency of average reservoir depth, porosity, permeability, oil column thickness, temperature, and API gravity to increase as the size of reserves increase. Average pressure, gas-oil ratios, and water saturation tend to decrease with an increase in reserve size.

More evidence

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Fig. 5a shows the percent of reserves at increasing depth intervals of 500 ft, 5b shows the percent of reserves at increasing porosity intervals of 1%, and 5c shows the percent of reserves at increasing permeability intervals of 200 md.

The percent of reserves increased with depth until a depth of 5,500 to 6,000 ft was reached and then decreased below 6,000 ft. The percent of reserves increased with increases in porosity until a porosity of 33% was reached, above which the percent of reserves decreased. The percent of reserves remained fairly constant with increases in permeability until a permeability of 2,100 md was reached and then decreased.

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Fig. 6a shows the percent of reserves resulting from increasing thickness of the oil-column in 10-ft intervals, 6b shows the percent of reserves resulting from increasing initial reservoir pressures of 200 psi, and 6c shows the percent of reserves resulting from increasing reservoir temperatures of 10°.

The percent of reserves with increased oil-column thickness remained high until 80 ft was reached, then became low until the highest percent of total reserves in reservoirs with an oil-column thickness of 150 to 160 ft was reached, followed by a second high point at 200 to 210 ft.

Thirty-three percent of reserves were at pressures between 2,600 to 2,800 psi with the remaining reserves being low despite increases in initial pressure. The percent of reserves increased gradually with increased temperature until the highest reserves at a temperature of 170 to 180 ft were reached and then the percent of reserves declined rapidly.

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Fig. 7a shows the percent of reserves resulting from increasing API gravity of one degree, 7b shows the percent of reserves resulting from increasing gas-oil ratios of 200, and 7c shows the percent of reserves resulting from increasing water saturation of 5%. Trend of reserves was very irregular but gradually decreased with an increase in API gravity, with the largest percent of reserves in API gravities of 24%.

The largest percent of reserves in gas-oil ratios were in values of 400 to 600 followed by a decrease in the percent of reserves with lower gas-oil ratios. The percent of reserves decreased with increases in water saturation after the largest percent of reserves were found with water saturations of 25% to 30%.

Inferences

To sum up, the percent of total reserves increased with increases in porosity but decreased overall with increases in depth, permeability, oil-column thickness, temperature, pressure, gravity, gas-oil ratio, and water saturation.

In most cases at first there is an increase in the percent of reserves with an increase in property values. In the cases of depth, porosity, permeability, pressure, temperature, gas-oil ratio, and water saturation after a maximum is reached there is an immediate drop-off to very small amounts of reserves.

Only rarely do the maximum values of any property show the maximum reserves, so it can be assumed that the highest values of properties are not the most important factor in determining the amount of reserves.

One might assume in this area that for the discovery of maximum reserves there is little point is exploring below 6,000 ft in areas where porosity exceeds 33%, where permeability exceeds 2,200 md, where pressure exceeds 2,800 psi, where temperature exceeds 180°, where gas-oil ratio exceeds 500, and where water saturation exceeds 35%. It appears that increases in oil-column thickness and API gravity do not have a great influence on the percentage of reserves present.

The influence of different type traps on reserves in the Frio reservoirs was also examined. Simple anticlines (SA) were traps for 23 reservoirs, 37% of the total with 33% of the reserves. Partly productive structures (PPS) were traps for 14 of the reservoirs, 22% of the total with 19% of the reserves.

Faulted anticlines (FA) were traps for 13 reservoirs, 21% of the total with 11% of the reserves. Fault-bounded anticlines or domes (FBA) were traps for nine of the reservoirs, 14% of the total with 32 % of the reserves.

Two of the reservoirs, 12% of the total with four percent of the reserves, were porosity pinchout traps across a nose (NPP), and one reservoir, slightly more than 1% of the total with less than 1% of the reserves, was a partly productive structure trap on a simple anticline (PPS & SA).

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Fig. 8a shows the average depth, porosity, permeability, and percent reserves by each type trap, 8b shows the average oil-column thickness, pressure temperature and percent reserves by each type trap, and 8c shows API gravity, gas-oil ratio, water saturation and percent reserves for each type trap.

Differences in the percent reserves between the graphs result from differences in scale among the various properties. Examination of the graphs shows the only property variation important in the percent of total reserves for fault-bounded anticlines was the increase in depth.

The only variations important for an increase in the percent of reserves in porosity pinchout traps were the increases in thickness and pressure. An increase in water saturation apparent had little or no effect on the percent of reserves. Other properties may be higher in other types of trap but apparently did not affect the percent of reserves present.

Reference

  1. Galloway, W.E., Ewing, T.E., Garrett, C.M., Taylor, N., and Bebout, D.G., "Atlas of Major Texas Oil Reservoirs," Bureau of Economic Geology, Austin, 1983.

The author

F.R. Haeberle, a consulting geologist, moved to Delaware, Ohio, after 20 years in Dallas. He has worked for Standard Oil Co. of Texas, Atlantic Refining Co., Mobil Oil Corp., Mayfair Minerals, and J.J. Lynn Oil Division. He holds BS and MS degrees in geology from Yale University and an MBA degree in finance from Columbia University Graduate Business School. E-mail: fhaeberle@ aol.com