Reservoir Characterization and Flow Simulation of a Low-Permeability Gas Reservoir: An Integrated Approach for Modeling Tommy Lakes Gas Field

Abstract

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 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 modeling, and history matching techniques.This study presents an integrated workflow for modeling the low permeability Doig gas reservoir. A stochastic geostatistical reservoir model was developed based on concepts emanating from an outcrop analog analyzed with terrestrial LiDAR technology and 60 wells that represent the fundamental rock characteristics, structure, facies proportions and petrophysical properties of the Doig Anomalously Thick Sandstone Bodies (ATSB). 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 4 lithofacies. An artificial neural network was used for training the logs of key wells (GR, NPHI, RHOB) and populating the facies distribution of uncored wells. Facies-based log-derived porosity, permeability, shale volume and water saturation were assigned to grid blocks using sequential Gaussian simulation (SGS). Finally, the Monte-Carlo simulation approach was used to rank the key variables affecting OGIP in the uncertainty and optimization process.Flow based techniques were used for up-scaling reservoir properties into the coarse simulation grid. The full field simulation model was calibrated with buildup data and hydraulic fracture modeling of single wells. Production of the Doig channel from comingled 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 concludes 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.

Quantitative Prediction Model for the Water–Oil Relative Permeability Curve and Its Application in Reservoir Numerical Simulation. Part 1: Modeling

“…The reservoir recognition can be achieved by reservoir geological modeling. Unfortunately, most applications of stochastic modeling have been limited to reservoir properties that are not related to fluid saturation, such as porosity and permeability, and the spatial variation of the relative permeability curve is not taken into consideration. − However, as one of the most important parameters in reservoir development, the relative permeability curve is the key parameter to describe water–oil two-phase flow characteristics and it affects the distribution law of oil and water greatly. With regard to the reservoir with a high degree of macroscopic heterogeneity and a low degree of microscopic heterogeneity, the heterogeneity can be reflected to a large extent by using different water–oil relative permeability curves for different depositional environments.…”