The Need
In recent years, natural gas companies operating in northeastern BC have produced increasing volumes of liquid hydrocarbons, or gases with significant liquid production, from unconventional reservoirs. While these tight rock formations are known to contain significant gas and liquid hydrocarbons in some areas, predicting the distribution and associated producibility (the measure of how easy or difficult it is to extract the hydrocarbon from the rock) of the gas and liquid hydrocarbons is complex and has not been well understood.
In comparison with conventional petroleum reservoirs, shales and tight reservoirs are fine-grained and have nano- to micro-metre scale pore systems. Characterizing these pore systems is important because they store and determine the path for gas and liquid hydrocarbons to move through the shale matrix.
Project Goals
This project set out to predict the distribution of gases and liquids in shale formations and their production rates, as well as introducing new methodologies and refining existing techniques.
This project had two goals:
- Development of better methodologies for quantifying gas and liquid in place in tight gas and tight oil reservoirs and measuring matrix flow characteristics (relative permeability and diffusivity); and
- Quantification of the gas and liquids in place and flow characteristics of important producing shales in northeastern BC using established and new methodologies.
Project Benefits
This research helps to focus energy exploration in northeastern BC, and improves existing and new exploration methods and production techniques.
Survey Area
The research program focused on the Exshaw, Doig, Montney, Duvernay, Nordegg and Wilrich formations along with equivalent strata, or rock beds, in northeastern BC. The work included studies in the Montney Play, and in the Horn River and Liard Basins, and the Cordova Embayment, as well as adjacent areas of the Western Canadian Sedimentary Basin.
How was the Data Collected?
The researchers used data collected at wells, regional mapping, detailed specialized analysis of core samples and cuttings in the lab, and water chemistry results from flowback tests. They developed new and innovative techniques and refined existing methods to better characterize the pore structure, permeability, and mineralogy of fine-grained reservoirs. Advanced modelling techniques were also used to assess fracture permeability and flow, and geochemical modelling of flowback water chemistry was conducted.
What was Found?
Overall, this multi-year, multi-researcher project increased understanding of the methods and testing for prediction of the behaviour of gas and liquids in unconventional reservoirs and how this can influence production. Principal investigator, Dr. Marc Bustin, guided, supervised, and consolidated the research and conclusions.
Individual investigations within the overall project include:
- PhD research by Eric Letham (2017) has made a major contribution to understanding the pore structure and resulting flow characteristics of shale.
- A detailed study of the volume, rheology, and chemistry of fluids during flowback after hydraulic completion of Montney Formation wells by MSc student J. Owen (2017).
- A multi-faceted study using petroleum systems analyses ground-truthed with fluid analyses and petrophysical and geochemical analyses of core and cuttings was undertaken by MSc student T. Wilson (in progress) to aid in prediction of hydrocarbon distribution, reservoir quality, and producibility of important Devonian shales, also published in Wilson and Bustin (2019).
PhD research undertaken by E. Munson involving a pore to basin scale study of the Duvernay Formation to understand the fundamental controls on reservoir development in shales. Of particular importance was to determine how permeability of shales to liquids varies with shale diagenesis and lithofacies.