Water?? We Don’t Make No Stinkin’ Water!

Robert M. Cluff and Keith W. Shanley
The Discovery Group Inc., 1560 Broadway, Ste 1470, Denver, CO 80202
[email protected]

One of the most common, oft repeated mis-conceptions about “basin-centered gas” plays is that the reservoirs do not produce any free formation water, and what little water is produced results entirely from the flow-back of completion fluids and from water of condensation in the gas stream. This notion is repeated at conference presentations, in peer-reviewed technical publications, field studies, press releases, and basin-scale resource assessments.

Based on extensive evaluation of reported water production from thousands of wells in the Green River, Uinta, and Piceance basins we conclude this idea is almost certainly false and is not be supported by actual field data – it is a myth that has been perpetuated for 30 years without critical examination of well performance. What is certainly true is that water production rates are generally “low”, typically less than 10 BWPD, and consequently they do not get noticed by field or office personnel as a problem that merits investigation or remediation.

Far more meaningful is to examine the actual produced water/gas ratio through time (WGR, usually expressed in bbls water/MMSCFG) and compare this with expected values for water of condensation based upon established dew point charts and basic thermodynamics. Surprising to some will be the fact that most “basin-centered gas” fields in the > 9000 ft depth range can have equilibrium water of condensation at reservoir temperature and pressure that equate to less than 2 bbls/MMSCFG at surface conditions. These values agree astonishingly well with the MINIMUM observed water production rates in these fields, confirming that some wells are indeed below critical water saturation and produce for all intents and purposes water free. But, on average wells in these same fields produce water at rates anywhere from 3 - 20 bbls/MMSCFG, with WGR generally increasing down dip. Because most tight gas wells produce gas at stabilized post-completion rates under 1 MMCFG/day they produce water at average rates somewhere in the 0.5 to 10 BWPD range, which directly leads to the misconception that the wells are producing dry gas and no formation water. Furthermore, because of relative permeability effects the effective permeability to gas decreases down dip as average water saturations gradually increase and, although the WGR climbs with improved relative permeability to water, the gas rate drops and the amount of water that can be lifted by the gas production remains low.

Examples of fields commonly thought of as “dry, basin-centered gas fields” that actually produce formation water far in excess of water of condensation include:

So why don’t we see the kinds of water production rates found in “conventional” oil and gas reservoirs? The answer is simply the petrophysics of liquid flow through tight formations won’t allow it. Liquid permeabilities to water in tight formations (< 1 md) are much less than 50% of the absolute (dry rock) gas permeability. For typical tight gas sands with absolute permeabilities in the 0.001 mD to 0.1 mD range (1 to 100 µD), the expected liquid permeability at 100% Sw ranges from a few nannodarcies (10^-9 D) to perhaps 30 µD at the high end. At any partial saturation to gas, which is a given for any well that has been completed as a gas well, these values quickly drop off to even smaller numbers. What is remarkable is how much water some of these wells produce at such low effective permeabilities to water.

The only zones capable of producing water at high rates (in the 10’s of bbls/day) are those with high effective permeability to water. Examples include rocks with much higher permeability such that they are grading into “conventional” reservoirs (e.g. Dakota, Moxa Arch; lower Main Almond, Washakie basin), and fractured zones after the initial gas charge in the fractures has been depleted.