E-v-e-r-y-t-h-i-n-g Has Got to Fit

Peter R. Rose is managing partner of Rose & Associates, Austin, Texas.

Sound assessment of the reserves potential of a wildcat prospect (as well as its derived profitability) requires the exploration team to estimate many different geotechnical and economic parameters (Table 1).

In nature, all the geotechnical parameters "fit" -- that is, the various physical properties of an undiscovered subsurface oil or gas reservoir are interrelated and compatible with each other, as well as with the geological characteristics of the parent trend or basin.

(Similarly, the economic attributes of the region should fit current price and cost schedules as well as historical ranges of variation -- but let's discuss economics in a later column.)

So whenever prospectors make estimates of the key geotechnical parameters attending any prospect -- ordinarily as probabilistic ranges -- all those parameters should fit.

(Actually, one of the underappreciated virtues of probabilistic estimating is that it's much easier to achieve such compatibility with ranges than with single-number estimates.)

Moreover, when the prospector has iterated and reiterated the various geotechnical parameters until they are all compatible, the resulting prospect assessment is probably just about right, given the uncertainties that always exist.

Of course, reality checks and plausibility checks provide effective ways to affirm that geotechnical forecasts are consistent with scientific principles and documented observations, and credible with respect to known statistical distributions (exponential or lognormal).

But substantial additional benefit is realized when individual parameter forecasts are reconciled with other related parameters.

Here are some examples:

Are the average net pay estimates compatible with the various productive area estimates?

Often these exhibit some dependency. A routine calculation and cross-check against net rock volume can resolve this.

Are the estimates of productive area (thus projected number of development wells) appropriate for the corresponding P90, P50 and P10 reserves outcomes?

Remember that P23 area corresponds to P10 reserves, and P77 area goes with P90 reserves.

Is the P99 prospect reserves estimate consistent with a mediocre little one-well field?

Characteristic P99 values of field-size distributions in mature onshore trends range from about 5,000 BOE to about 20,000 BOE. The most common cause of reserves overestimation is not that the high-side estimate is too high, rather that the low-side estimate is too high!

Taking depth into account, are forecast ranges for HC-Recovery Factor (bbl/af or mcf/af) compatible with analog producing fields in the trend?

Is the P1 average porosity forecast less than about 30 percent? Is the P99 average porosity forecast equal to your effective porosity cut-off? Do forecasts of average porosity ranges fit with observed average porosities for subject formations?

Are forecasts of Initial Production Rate compatible with estimates of prospect reserve volumes, thickness, HC-Recovery Factor and drive mechanism?

Do percentage decline forecasts fit those of analog producing fields? Are they compatible with reservoir type, HC-Recovery Factor and drive mechanism?

Bottom line: Remember that all such parameters fit in nature. If you take pains as a professional prospector to be sure they all fit together in your prospect, chances are that you've got the geotechnical picture -- and the prospect evaluation -- about right.