Summary
The Tommy Lakes field is located in northeastern British Columbia, Canada,
and is one of the largest Middle Triassic gas pools within the western Canada
sedimentary basin (WCSB). The major gas-production formation (Halfway/Doig
reservoirs) at the Tommy Lakes field corresponds to shoreface sands with
permeabilities ranging between 0.1 and 3 md, and porosities of 3 to12%. For the
purpose of production optimization and field development, a full-field
reservoir model was developed with the integration of advanced reservoir
characterization, hydraulic-fracture modelling, and history-matching
techniques.
This study presents an integrated workflow for modelling the
low-permeability Doig gas reservoir. A stochastic geostatistical reservoir
model was developed on the basis of concepts emanating from an outcrop analogue
analyzed with terrestrial light detection and ranging (LiDAR) technology and 60
wells that represent the fundamental rock characteristics, structure, facies?
proportions, and petrophysical properties of the Doig anomalously thick
sandstone bodies (ATSBs). Structural tops were interpreted from well logs and
permeability/porosity relationships established from quantitative log analysis
and core/log calibration. Facies were identified in cored intervals and were
further grouped into four lithofacies. An artificial neural network (ANN) was
used for training the logs of key wells [gamma ray (GR), neutron porosity
(NPHI), and bulk density (RHOB)] and populating the facies distribution of
uncored wells. Facies-based log-derived porosity, permeability, shale volume,
and water saturation were assigned to gridblocks using sequential Gaussian
simulation (SGS). Finally, the Monte Carlo simulation approach was used to rank
the key variables affecting original gas in place (OGIP) in the uncertainty and
optimization process.
Flow-based techniques were used for upscaling reservoir properties into the
coarse simulation grid. The full-field simulation model was calibrated with
buildup data and hydraulic-fracture modelling of single wells. Production of
the Doig channel from commingled wells was allocated systematically in order to
achieve a good match of the gas-production history and bottomhole pressures.
Sensitivity analysis of fracture half-length and its impact on ultimate gas
recovery was investigated. This concluded with an integrated development
strategy.
It is concluded that integration of multiple domains leads to a valid
full-field reservoir model, which is critical in developing an integrated
strategy, predicting reservoir performance, and optimizing gas production.
© 2011. Society of Petroleum Engineers
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History
- Original manuscript received:
20 August 2010
- Meeting paper published:
20 October 2010
- Revised manuscript received:
20 January 2011
- Manuscript approved:
23 February 2011
- Published online:
22 April 2011
- Version of record:
2 May 2011
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