Summary
Structural, stratigraphic, and petrophysical uncertainties result in a wide
range of geologic interpretations. For fields with a long production and
pressure history, 3D dynamic simulations have been very useful in providing
feedback to geologic modelers, which results in improved static models. For
this study, we developed an integrated static and dynamic workflow to create a
range of probabilistic simulation models to forecast dry-gas production under
several production scenarios in the Chuchupa field.
We selected eight geologic interpretations, representing the range of
original gas in place (OGIP) and reservoir geometries determined in the static
modeling, to perform dynamic history matches. The OGIP range of the models with
very good history matches corresponds closely to the P10 to P90 OGIP range
calculated from static modeling.
In addition, we calibrated the various models with historical bottomhole and
tubinghead flowing pressures and coupled the reservoir model with a network
consisting of surface lines and equipment, pipelines from two platforms to the
onshore sale-point station, and multistage compression to 1,215 psia. The set
of probabilistic models is currently used to evaluate various production and
market scenarios.
Introduction
Chuchupa field has produced 1.9 Tscf of dry gas, or approximately 40% of the
OGIP. At the time of this study, three new horizontal wells were being planned,
and new gas-sales agreements were being considered. Recent seismic
reinterpretation, a new stratigraphic study, and a revision of the
petrophysical model resulted in new probabilistic static models for the
field.
While these static models were being built, a parallel numerical-simulation
study was conducted to determine the range of OGIP values that could be
successfully history matched. Nine numerical reservoir models were generated by
applying pore-volume multipliers to the prior-generation reservoir model,
yielding a range of OGIP from 3.8 to 6.6 Tscf. We attempted to history match
each of these nine models by using an optimization routine to adjust aquifer
support, vertical transmissibility across a potential seal, and rock
compressibility. The optimization routine proved to be a very useful and
efficient tool to attain good-quality history matches in short periods of time.
Good matches were obtained for models with OGIP ranging from 4.3 to 5.8
Tscf.
On the basis of this information, the geologic modelers revised
petrophysical parameters and generated 27 static models, encompassing three
structural interpretations, three porosity distributions, and three possible
positions of the gas/water contact (GWC). From experimental design, we obtained
P10, P50, and P90values of 4.1, 4.7, and 5.3 Tscf, respectively. We scaled up
and built reservoir-simulation models on eight of these models and performed
history matches. The observed parameters to match were static well pressures
and the absence of water production. Six of the eight models were
satisfactorily history matched, with reasonable adjustments to aquifer
strength, vertical transmissibility, and rock compressibility. The successfully
history-matched models are within the P10 to P90 OGIP range.
We selected three models to forecast future gas production. These models
match the P10, P50, and P90 OGIP values determined in the probabilistic static
model and combine the low, mid, and high structures, porosity and
Swi distributions, and the range of GWC positions.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
5 March 2006
- Meeting paper published:
15 May 2006
- Revised manuscript received:
19 January 2007
- Manuscript approved:
19 January 2007
- Version of record:
20 August 2007
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