GULF COAST TERTIARY-3 [CONCLUSION] MAXIMUM HYDROCARBON WINDOW DETERMINATION IN SOUTH LOUISIANA

W.G. Leach
Consulting Petroleum Engineer
New Orleans

This is the third and final part of a three part article about the distribution of hydrocarbons in the Tertiary sands of South Louisiana.

Based on many individual plots, it was found that hydrocarbon distribution will vary according to the depth of abnormal pressure and lithology.

For example, Fig. 19 consists of four plots showing gas distribution as a function of abnormal pressure and depth. In this analysis, lithology is statistically related to depth. The primary reason for this is that, with increased depth, shale becomes more prevalent than sand in South Louisiana Tertiary sediments.

The four plots in Fig. 19, from left to right, show that the center of maximum gas distribution is consistently dropping farther below the top of abnormal pressure with increased depth.

Initially it was not known what parameters were causing the maximum hydrocarbon distribution to shift, but three facts were known.

First, all fluids are constantly trying to migrate up to the top of abnormal pressure or the highest point of fluid equilibrium.

Second, these fluids have to fracture up to the point of fluid equilibrium.

Third, it has already been observed that the fracture gradient for the South Louisiana Tertiary (Fig. 16) increases with depth.

Therefore it was concluded that the position of maximum gas distribution to abnormal pressure is primarily a function of formation fracture strength. In other words, the greater the fracture strength the farther below the top of abnormal pressure will the maximum concentration of gas most likely be encountered.

MAXIMUM HC WINDOW

The relation of maximum hydrocarbon distribution to formation fracture strength or depth opens the door to the use of a maximum hydrocarbon window (MHW) technique (Fig. 20).

This MHW technique can be used as a decisionmaking tool on how deep to drill a well, particularly how deep to drill a well below the top of abnormal pressure.

For example, gas distribution in Fig. 20 is shown as a percent of total gas encountered above and below abnormal pressure as a function of well depth. When the top of abnormal pressure is at a depth of 12,000 ft, 95% of the gas distribution has been statistically penetrated at a depth 2,400 ft below the top of abnormal pressure.

But when abnormal pressure is at a depth of 18,000 ft, this 95% concentration point is not penetrated until 4,200 ft below the top of abnormal pressure. In other words, a well should be drilled about 1,800 ft deeper below the top of abnormal pressure at 18,000 ft than when the top of abnormal pressure is encountered at 12,000 ft.

This is necessary in order to drill through the 95% concentration level. However, economic factors involving smaller reservoirs and higher drilling cost may be a limiting factor at greater depths.

MHW TECHNIQUE BENEFITS

The need for both exploration and exploitation enhancement in deep well drilling is shown in a randomly selected control sample of 309 wells (Fig. 21).

The plot shows production vs. number of wells. The 309 well control sample represents the approximately 1,200 wells completed to date between 15,000 ft and 18,000 ft in the onshore Tertiary sands of South Louisiana.

About 90% of the production was produced by 50% of the wells. This is typical of most wells drilled below 15,000 ft in the area. The fact that 50% of the wells produced only 10% of the production illustrates the need for better insight into exploitation drilling in deep Tertiary sands.

Use of the MHW technique would have increased production in the wells completed between 15,000-18,000 ft by an average of 400%/well.

This conclusion is based on the analysis of estimated gas reserves from the 309 well control sample (Fig. 22).

Using actual reserve data, the curve on the right represents the probability of gas reserves per well inside the MHW. The curve on the left shows the probability of gas reserves per well outside the MHW.

There is a 40% chance that wells completed inside the MHW will produce 4 bcf/well; however, wells completed outside the MHW have only a 10% chance of producing 4 bcf/well.

Use of the MHW technique on wells drilled below 18,000 ft, described by Fertl and Leach,5 would have increased average production by almost 500%/well. It is further estimated that at least 30% of the 439 dry holes could have been avoided. This would have resulted in industry savings of more than $900 million.

The MHW technique has the potential to enhance exploration and development in all clastic sedimentary basins throughout the world.

The technique should be of particular benefit when drilling gas wells below 12,000 ft in Upper Tertiary sediments. However, hydrocarbon distribution associated with the top of abnormal pressure for any combination of clastic sediments should be predictable with the MHW technique.

A special MHW plot for a particular sand/shale environment should be developed for maximum benefit. For example, MHW plots were developed for the Camerina and Miogyp gas sands (Frio) in Southwest Louisiana.

The maximum gas window for the Camerina sand is centered about 2,500 ft below the top of abnormal pressure (Fig. 23). Gas distribution is divided equally above and below this point (Table 3).

Almost 90% of the Camerina gas production was encountered in this distribution level. To date more than 1.6 tcf of gas has been produced from 99 Camerina completions in this South-west Louisiana area.

The Miogyp gas sands (Fig. 24, Table 4) further illustrate the need for different regional geological distribution plots.

The production distribution plot in Fig. 24 is reflecting lithological differences in wells producing from the Miogyp sands. The subtle plateau at 3,500 ft below the top of abnormal pressure represents production from Miogyp completion up-thrown to a series of major regional faults.

However, the major peak at 6,500 ft below the top of abnormal pressure reflects production from Miogyp reservoirs over leaned by massive transgressive shale wedges. The production distribution of wells encountered below the massive shale is shown in Fig. 25.

The massive shales encountered above the Miogyp sands in these downthrown blocks have much higher fracture gradients.

Shales have higher fracture gradients than sand. These higher fracture gradients restrict the vertical migration of fluids in the hydrodynamic defluiding process.

Consequently, the maximum hydrocarbon window in this type of geological environment will always be found much deeper below the top of abnormal pressure.

FUTURE E&D POTENTIAL

The MHW technique should be applicable in all elastic sedimentary basins where abnormal pressure is encountered.

The MHW technique can best be used in the initial exploration planning stage in deciding where and how deep to drill. Moreover, the MHW technique can be used for any particular sand/shale type environment if the depth of abnormal pressure is known.

The MHW plot should be from wells that have produced from a similar stratigraphic type of sand/shale environment.

Since the largest distribution of hydrocarbon reserves is found associated with the top of abnormal pressure, the first exploration prerequisite for a new clastic sedimentary basin, area, or prospect should be mapping the top of abnormal pressure.

In new clastic basins where there is little or no well control, the top of abnormal pressure must be predicted from seismic velocity data.

Since rock velocity changes with rock bulk density, the change in pore pressure gradient due to undercompaction or abnormal pressure can be detected. Drilling engineers have used this technique for several years to determine the setting depth for protective casing.

After drilling begins, the seismic velocity data can be augmented by mud weights, open hole well logs, and formation pressure tests.

Top of 12.5 ppg mud in a well is a good selection point for the top of abnormal pressure.

But the most practical way to determine the depth of abnormal pressure is from the top of low density shale.

The use of abnormal pressure mapping and the MHW technique in conjunction with existing geophysical and geological methods dictates the need for multidisciplined teams.

A team of geophysicists, geologists, and engineers is needed at an early exploratory stage in order to:

1. Map the top of abnormal pressure

2. Predict maximum hydrocarbon distribution patterns

3. Locate better quality reservoir traps

4. Evaluate economics of the total program.

In mature areas, including old fields, the MHW technique can be used to ensure that all maximum gas and oil environments have been sufficiently evaluated by existing wells. Regional composite mapping of pressure/temperature crossover areas may prove up additional prospects. Also, mapping the top of a particular temperature isotherm may help locate new hydrocarbon migration routes.

ACKNOWLEDGMENTS

The author expresses appreciation to Texaco USA Eastern E&P Region for making this study possible and to the late Walter H. Fertl for his encouragement and insight on this work.

REFERENCES

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