Summary
This study presents a new way to model high secondary porosity, mainly vuggy
porosity, in naturally fractured reservoirs. New solutions are presented for
two cases, one in which there is no primary flow through the vugs (which is an
extension of the Warren and Root model) and one in which the dissolution
process of pore throats has created an interconnected system of vugs and caves.
In both cases, there is an interaction between matrix, vug, and fracture
systems. New insights are provided.
Both pressure and production responses during transient and
boundary-dominated flow periods are explored. In transient well tests, for the
case in which there is no primary flow through the vugs, a change of slope
could be present during the transition period. Thus, this study shows that
slope ratios of 2:1 of an early- or late-time segment vs. a transition segment
do not necessarily imply transient interaction between matrix and fractures. It
is also shown that the presence of vugs and caves may have a definitive
influence on decline-curve and cumulative production behaviors; therefore, it
is necessary to incorporate vuggy porosity in the process of type-curve
match.
Finally, the use of the methodology obtained in this work is illustrated
with synthetic and field examples.
Introduction
Most of the world’s giant fields produce from naturally fractured and vuggy
carbonate reservoirs that have complex pore systems, mainly because carbonate
rocks are particularly sensitive to post-depositional diagenesis, including
dissolution, dolomitization, and fracturing processes. Complete leaching of
grains by meteoric pore fluids can lead to textural inversion, which may
enhance reservoir quality through dissolution or occlude reservoir quality
through cementation.
Some works have classified carbonates on the basis of fabric-selective and
nonfabric-selective pore types. The nonfabric-selective types are vugs and
channels, caverns, and fractures. For the purpose of this work, no distinction
is made on vugs, caverns, and channels, and they will be denoted by the term
vugs. Thus, vugs may vary in size from millimeters to meters in diameter.
Vugs are the result of carbonate and/or sulfate dissolution. From core
observations, the matrix-porosity types adjacent to the vuggy zones are moldic,
solution-enlarged microfractures and solution-enlarged intercrystalline. Thus,
it is possible to have a permeability enhancement adjacent to the vuggy
zones.
Three porosity types (matrix, fractures, and vugs) are usually present in
naturally fractured, vuggy carbonate reservoirs. The determination of
permeability and porosity in vuggy zones from core measurements is likely to be
pessimistic because of sampling problems. In areas lacking cores, openhole
wireline logs may be used to help identify vuggy zones; however, vugs are not
always recognized by conventional logs because of their limited vertical
resolution.
Vuggy porosity is common in many carbonate reservoirs, and its importance in
the petrophysical and productive characteristics of a carbonate rock has been
recognized by several works.
Vugular porosity can be subdivided into connected and disconnected types.
The effect of vugs on permeability is related to their connectivity. High
permeability may be present in vuggy zones by solution enhancement of pore
throats, which creates an interconnected system of vugs. The presence of
high-porosity and high-permeability vuggy zones may diminish waterflood
effectiveness and leave a large amount of bypassed oil in the
lower-permeability matrix. One purpose of our work is to present a technique to
identify high secondary porosity, mainly vuggy porosity.
It has been observed in the literature that vugular zones strongly influence
production performance. This reference addresses the problem of modeling vuggy
naturally fractured reservoirs, allowing the possibility of primary flow
through vugs, and develops a method to identify vuggy reservoirs on well tests
and decline curves, evaluate porosity associated with vugs and fractures, and
determine vuggy connectivity.
The proposed model can be used in numerical simulators. Some comparisons
between the results of analytical solutions derived in this work and those
obtained with a numerical simulator, which uses the proposed model, are
presented.
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
7 November 2002
- Revised manuscript received:
3 December 2004
- Manuscript approved:
21 December 2004
- Version of record:
15 April 2005
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