The McElroy field produces approximately 17,000 BOPD (barrels of oil per da
y) under a mature waterflood from the Permian Grayburg Formation. The main
pay zone in the reservoir is primarily peloidal dolograinstones/packstones
with interparticle/intercrystalline porosities. The central portion of the
field is more heterogeneous because of thin high-porosity and high-permeabi
lity vuggy zones. The occurrence of these zones is confirmed by core descri
ption and measurements, porosity logs, tracer studies, and injectivity meas
urements. These thin high-porosity and high-permeability vuggy zones dimini
sh waterflood effectiveness ana leave millions of barrels of bypassed oil i
n the lower permeability matrix.
A method was developed to identify the vuggy zones on logs, create geostati
stical models of porosity and permeability incorporating the vuggy zones, a
nd characterize them in simulation models. The methodology involved the fol
lowing: (1) developing a log trace to identify zones of high secondary poro
sity, mainly vuggy porosity, in the area of the field that was modeled, (2)
creating a detailed geostatistical model (1 million cells) of total porosi
ty using well-log data, (3) creating a geostatistical permeability model ba
sed on total porosity, (4) creating a separate detailed geostatistical mode
l of secondary porosity, and (5) superimposing exceptionally high permeabil
ity in areas of the permeability model defined by high secondary porosities
.
The detailed permeability models were scaled-up to 12,000-cell models for s
imulation studies. The models incorporating vuggy permeability distribution
s showed a far superior history match of primary and waterflood processes t
han did models that did not incorporate vuggy permeability; these models al
so showed good-quality history matches for individual wells. Successful his
tory matching of the simulation models validates our method and indicates t
hat core data underestimate the permeability of vuggy zones due to sampling
and measurement issues.