A review of over 200 Dunvegan wells indicates that treatments receiving a tail-in of ceramic or RCS outperform sand fracs. Ceramic tail-ins outperform RCS tail-ins, demonstrating that improved conductivity is beneficial in this formation.
In the Western Canadian Sedimentary Basin (WCSB), fracturing stimulations have been done for 70 years. In Canada, the government, service companies, and well operators accumulate massive volumes of information. This information exists in the form of paper files and databases of varying detail containing well and treatment information. The information age makes production data available making another leap in determining fracture designs based on real production results of past treatments.
In the past few decades, a common way operators started the design process was to approach service companies for their experience in an area and formation. From around 1955, many new designs were created by referring to old designs. Then the industry used designs that were pumped in the field which progressed in later years to stimulation that were pumped to completion. This sometimes progressed to job designs pumped with production from the stimulated formation. More value is attained by looking at optimal post fracture production using actual results not calculated, uncalibrated predictions. This is most powerful when the production results are matched to calibrated fracture models, reservoir models and petrophysical analysis to continue area projects in stimulated a formation.
This case study covers 3,600 square miles from 58-19W5 to 68-02W6 of the Dunvegan formation. It is a tight, water sensitive formation usually producing gas. Geologically, the Dunvegan has less than 1 mD permeability. The success of various fracturing techniques are evaluated on several levels including a review of the 203 out of the 406 wells in the region. The fracturing strategy comparisons will evaluate base fluid selection, proppant type, and the amount of proppant. The current commodity prices are used to calculate the optimized results versus the vast amount of information that was collected in the past using lower prices.
Hydrocarbon based fracturing fluids were used 85% of the time as one would expect based on the geological evaluation of the area. However, the infrequent and larger water fractures have an IP rate of 1.5 MMscf/day using 100,000 lb of proppant where the more frequent and smaller hydrocarbon fractures are 1.2 MMscf/day using 40,000 lb. Total recovered gas is 4 times higher for the water fractures compared to the hydrocarbon based fractures. The optimization of the hydrocarbon fractures with respect to the pounds of proppant used will also be examined since the most common size was 33,000 lb but was found to have optimal IP gas production using 66,000 lb.
Author(s): BJ Services Co. Canada, T.T. Leshchyshyn and J.D. Thomson
Paper Number: SPE 97249