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Estimating Reserves in Tight Gas Sands: Geological Complexities and Controversies


Creties Jenkins, DeGolyer and MacNaughton

Tight gas sand wells have highly-variable performance, with estimated ultimate recoveries (EUR’s) ranging from less than 10 MMCF to more than 10 BCF per well.  While drilling and completion practices play a critical role in determining EUR, there are also a number of geological and petrophysical factors that strongly affect it.  Many of these factors are poorly-understood and there is considerable controversy over their nature, influence, and predictability.  These factors include:

  1. The nature of the gas accumulation as either “basin-centered” or “conventional”:  Basin-centered accumulations are interpreted as areally-extensive, overpressured, gas-charged compartments with technically recoverable volumes ranging from tens to hundreds of trillions of cubic feet of gas.  However, if the recoverable gas is actually contained in low-permeability conventional traps, then the associated gas volumes are much smaller.  Which of these is more common and how do we distinguish them?
  1. Petrophysical properties: Relationships between porosity and permeability vary by lithofacies and basin, and saturations can be difficult to calculate from logs given variations in Archie parameters, Rw, and mineralogy.  It is not unusual to have a gas-in-place uncertainty of plus or minus 50%, even in fields with large datasets and long production histories.  What can be done to reduce this uncertainty?
  1. Net pay thickness: Multiple cutoffs (permeability, porosity, clay volume, water saturation) are used to count net pay, and the cutoff values tend to be different for every reservoir.  How do we calibrate the cutoffs?  Can we reasonably compare net pay thickness from one reservoir to the next?  How do we verify that poorer quality pay actually contributes?
  1. The hydraulic connectivity of producing sandbodies.  Some fields can effectively drain sandbodies with a well spacing of 80 acres, while others are encountering untapped sandbodies at a 10-acre spacing or less.  Can we predict the degree of connectedness and how it changes across a field using geoscience data, or can we only understand this through pilot infill drilling projects and well testing?
  1. The role of “sweet-spots”:  A small minority of wells commonly have much higher EUR’s than the rest.  What geological factors are responsible for this and what tools and techniques can we use to identify them? Should we accept the notion that these are “statistical plays” and that the large variation in EUR’s can neither be understood nor used to high-grade drilling opportunities?
  1. The enigma of natural fractures:  Tremendous effort has been devoted to locating fractures, which can serve as higher permeability gas conduits. Techniques used for this purpose include seismic attributes, core description, and remote sensing among many others.  Have any techniques (or combination of techniques) been shown to consistently predict where fractures will occur?  And, when found, do these fractures contribute gas or water?
  1. Contributions of other lithologies:  Tight sands are charged from coals or shales that may be in stratigraphic contact with the sands over very large areas. Do these lithologies “re-charge” the sands as they are depleted, and if so, how do we quantify their contribution?
  1. Well decline behavior: Tight sand wells exhibit very flat initial decline curve behavior due to transient flow and/or contributions from multiple layers.  This decline steepens with time as wells transition to boundary-dominated flow.  What geological factors control this behavior and how can these insights be used to help predict the long-term decline behavior of wells?

This talk will briefly explore these factors, followed by a discussion with participants regarding their experiences in tight gas sands.


AAPG Search and Discovery Article #90098©2009 AAPG Education Department, Houston, Texas 9-11 September 2009