Summary
A Tcf-class gas field has been producing over several decades in Japan. The
reservoir body comprises stacked rhyolite lava domes erupted in a submarine
environment. A porous network developed in each dome and rapid chilling on
contact with seawater caused hyaloclastite to be deposited over it. Although
hyaloclastite is also porous in this field, its permeability has been reduced
dramatically by the presence of clay minerals. Impermeable basaltic sheets and
mudstone seams are also present. Each facies plays a specific role in the
pressure system.
Stratigraphic correlation originally identified multiple reservoirs. Gas has
been produced almost exclusively from the largest one. However, following 10 to
20 years of production, the pressures within unexploited reservoirs were
noticed to have declined at a variety of rates. Unusual localized behavior has
also been observed. Because seismic data were not proved particularly
informative, we decided to remodel the entire system by specifically using
pressure data.
We employed a combination of multipoint geostatistics and probability
perturbation theories. This approach successfully captured the curved facies
boundaries within stacked lava domes while accounting for pressure data by
means of history matching to address nonstationarity in the real field.
Building a suitable training image is commonly a difficult aspect of multipoint
methods and poses particular problems for volcanic reservoirs. It was
accomplished here by iteratively adjusting the prototype until satisfactory
history matching was achieved with a reasonable number of perturbations.
Ambiguous reservoir boundaries were represented stochastically by populating a
predetermined model space with pay and nonpay pixels.
The modeling results closely simulate measured pressure histories and appear
realistic in terms of both facies distributions and reservoir boundaries. They
suggest that uneven pressure declines between different units are caused by the
tortuous flow channels that connect them. The results also account for the
unusual smaller-scale pressure performances observed. The final training image
obtained here indicates more intensive spatial variations in facies than
previously appreciated. Original gas in place (OGIP)estimates made with 20
equiprobable realizations are scattered within ±15% of the mean value.
Estimates of incremental recovery made by drilling a step-out well reveal
greater variation than those made by installing a booster compressor, which
quantifies a higher associated geological risk.
© 2007. Society of Petroleum Engineers
View full textPDF
(
2,937 KB
)
History
- Original manuscript received:
5 January 2005
- Meeting paper published:
5 April 2005
- Revised manuscript received:
24 September 2006
- Manuscript approved:
17 October 2006
- Version of record:
20 February 2007
View Cart
