Statistical Modelling for the Source Rock Parameters of the Montney Formation, NE British Columbia, Canada

Hydrocarbons in self-sourced reservoirs are determined by the concentration and maturation of organic matter in sediments. As a result, lowering risk in unconventional resource research and development requires knowledge of hydrocarbon potentiality factors. The geochemical data for the Montney Formation samples studied suggest that it is a fair to good source rock with type IV kerogen that can generate gas in general. The statistical modelling of the analyzed data reveals a valuable technique for identifying characteristics, clusters, and linkages that affect source rock assessment. The Spearman’s correlation coefficient showed a good positive correlation between the total organic carbon (TOC) and free hydrocarbons (S1), generating potential (S2), and potential yield (GP). There was a weak correlation with the maturity index (Tmax) and hydrogen index (HI) and a highly negative correlation between the TOC and oxygen index (OI). On the other hand, the principal component analysis (PCA) showed the presence of three factors affecting the source rock evaluation. Factor 1 included TOC, S1, and S2, which are related to organic richness and hydrocarbon potentiality; factor 2 contained the production index (PI), and the generated CO2 (S3) was related to the organic matter source. Factor 3 included the Tmax and HI related to the type of organic matter and thermal maturity. In addition, the TwoStep cluster analysis separated the source rock in the study area into two major groups. Cluster 1 is characterized relatively by high HI, TOC, S1, S2, and PI, with Tmax < 455 °C indicating good source rock in the mature level with the capability to generate little oil and condensate gas. Cluster 2 is characterized by relatively low HI, TOC, S1, S2, and PI, with Tmax > 455 °C, indicating an over-mature source rock in the dry gas window.

Single Well Microseismic Monitoring Leveraging Hybrid Cable Combining Both DAS and Traditional Geophones

The single monitoring well configuration is a favorable option for microseismic monitoring considering risk and cost. It has commonly been used in various industries for decades. When using a single monitoring well, we rely among other things on the waveforms’ polarization information to accurately locate detected microseismic events. Additionally, using a large array aperture reduces hypocenter's uncertainty. Instead of solely relying on 3C geophones to achieve such objectives, we propose to combine 3C sensors and distributed acoustic sensing (DAS) equipment. It is quite a cost-effective solution, and it enables us to leverage each system's strength while minimizing their respective limitations when considered individually. We present the technical feasibility of such a hybrid microseismic monitoring system using data acquired during a monitoring campaign performed in the Montney formation, Canada. In this dataset, the optic fiber (DAS) is located in the wireline cable used to deploy the 3C geophones; themselves located at the bottom of the DAS wireline cable. Though different acquisition systems are employed for the geophone array and the DAS array, both datasets are GPS time stamped so that data can be processed properly. We scan the DAS data using an STA/LTA event detection, and we integrate with the 3C geophone data. We find the microseismic waveform in both the DAS and the geophone sections and confirm the arrival times are consistent between DAS and geophones. Once datasets are merged, we determine hypocenters using a migration-based event location method for such hybrid array. The uncertainty associated with the event located using the hybrid DAS – geophone array is smaller than for any of the systems looked at independently thanks to the increased array aperture. This case study demonstrates the viability and efficiency of the next generation of a single well acquisition system for microseismic monitoring. Not only does it lower event location uncertainty, but it is also more reliable and cost-effective than the conventional approaches.

Evaluation of Reservoir Quality and Forecasted Production Variability along a Multi-Fractured Horizontal Well. Part 2: Selected Stage Forecasting

The current practice for multi-fractured horizontal well development in low-permeability reservoirs is to complete the full length of the well with evenly spaced fracture stages. Given methods to evaluate along-well variability in reservoir quality and to predict stage-by-stage performance, it may be possible to reduce the number of stages completed in a well without a significant sacrifice in well performance. Provision and demonstration of these methods is the goal of the current two-part study. In Part 1 of this study, reservoir and completion quality were evaluated along the length of a horizontal well in the Montney Formation in western Canada. In the current (Part 2) study, the along-well reservoir property estimates are first used to forecast per-stage production variability, and then used to evaluate production performance of the well when fewer stages are completed in higher quality reservoir. A rigorous and fast semi-analytical model was used for forecasting, with constraints on fracture geometry obtained from numerical model history matching of the studied Montney well flowback data. It is concluded that a significant reduction in the number of stages from 50 (what was implemented) to less than 40 could have yielded most of the oil production obtained over the forecast period.