Summary
The lower Tertiary Wilcox, Yegua, and Vicksburg formations are prolific
natural gas plays in south Texas that have been extensively drilled and
produced from low-permeability, fine-grained sandstones. It is not unusual to
encounter several potential pay zones in each well. What is lacking is a proven
formation-evaluation method to determine the highest-productivity water-free
producing zones from multiple intervals that can be casually identified on the
logs as hydrocarbon-bearing. Connate-water resistivity (Rw) determination is
not a major problem, given that many water-bearing sands are usually present.
Accurately estimating true clay content, porosity, irreducible water volumes,
and permeability present the greatest challenges.
A new spectroscopy-based petrophysical interpretation methodology has been
developed that makes use of several unique measurements, namely quantitative
elemental concentrations and lithology logs obtained from capture gamma ray
spectroscopy devices in open or cased wells. These measurements allow us to
more accurately define the clay content, mineralogy, and matrix properties of
each potential zone. One significant finding obtained from these measurements
is the occurrence of calcite cements detected in many sands that cause a
pessimistic density porosity to be computed if not accounted for. This calcite
cementation appears to vary dramatically in a lateral sense, indicating that
its presence should not be used to condemn an entire layer as being too tight
for production, nor provide irrefutable evidence of the expected ability of the
layer to contain a hydraulic fracture.
The enhanced elemental and mineralogical analyses provided by the
spectroscopy measurements also allow for more accurate bulk volume irreducible
water calculations and a means to correct the neutron porosity for clay and
matrix effects. By comparing irreducible water volume to bulk volume
hydrocarbon, an accurate prediction of water production can be determined. Oil-
and gas-bearing intervals can be identified easily from crossover of the
matrix-corrected neutron porosity when used in conjunction with the
matrix-corrected density porosity. Results are illustrated with several case
studies from wells recently drilled and now producing from the Wilcox, Yegua,
and Vicksburg formations.
Introduction
Formation evaluation in the south Texas Wilcox, Yegua, and Vicksburg sands
is problematic because of the influence of the varying clay volume, average
grain size, and hydrocarbon type on the logging measurements. In these south
Texas shaly sands, the volume of clay minerals traditionally has been
approximated from gamma ray (HSGR), spontaneous potential (SP), or
density-neutron logs. Each of these methods has serious limitations. For
example, if nonclay sources of radioactivity are present, estimates of clay
volume from gamma ray will be too high, resulting in reduced estimates of
effective porosity, pessimistic reserve calculations, and an overall reduction
in the valuation of the reservoir’s potential. The clay volume also has an
adverse affect on the ability to locate gas zones using the neutron-density
crossover technique. The crossover is suppressed in gas zones in proportion to
the amount of clay present. The presence of mud-filtrate invasion will also
suppress the neutron-density crossover in gas zones.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
16 September 2004
- Meeting paper published:
7 November 2004
- Revised manuscript received:
7 September 2005
- Manuscript approved:
12 September 2005
- Version of record:
20 February 2006
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