In an effort to continuously optimize drilling operations and economics, an operator examined the impact of adding hollow-glass spheres (HGS) directly to the drilling fluid formulation instead of performing underbalanced drilling operations. Both nitrogen and HGS were believed to reduce hydrostatic pressure of the mud column in the hole, resulting in higher drilling rates of penetration (ROP) and fewer mud losses to the wellbore.Invert emulsion fluid was blended with HGS on three drilling rigs using a specialized, environmentally acceptable mixing system to help reduce density. HGS concentration and fluid density were monitored and maintained while drilling over the period of one to three weeks for these three wells. The proper type of centrifuge and its setup is fundamental to maintaining low-gravity solids (LGS) at an acceptable level for proper fluid management while maintaining the desired concentration of HGS.Drilling mud density was reduced, as expected, and mud loss was minimized as a result. Overall costs were reduced because of less invert emulsion fluid loss, a reduction in the amount of lost-circulation material mixed compared to previous wells in the area, and less time spent on the drilling rig attributed to not having to stop to mix lost-circulation material or prepare new invert emulsion fluid volumes to replace losses. A significant ROP increase was not observed during this trial. The addition of HGS is a cost-effective solution to help reduce fluid loss in the Kakwa field of the Western Canadian Sedimentary basin. This trial helped reduce overall rig time, and fluid loss experienced was less than in previous wells in which this technology was not used.This paper provides information on HGS as an economic alternative to nitrogen to help reduce the hydrostatic pressure of invert emulsion drilling fluids using a small-footprint, environmentally acceptable mixing system.

One of the most important hydrocarbon resources in the Western Canadian Sedimentary Basin (WCSB) is the Montney tight shale formation, which extends approximately 55,000 square miles from northeast British Columbia to northwest Alberta. Operations in the Alberta deep-basin Montney have proven this area to be one of the continent's most productive unconventional resource plays. As part of the field development plans, cores are cut from the reservoir rock to directly measure source rock properties through analysis of core samples and calibrating wireline logs with data extracted from the core samples. The subsurface geology of the upper hole section in this particular area is complex, where reactive, swelling, and fissile shale as well as coal beds and lost-circulation zones extend across 2700 m of the openhole section. As such, historically in this field, the Montney has been cored using a weighted oil base system incorporating water contamination into the core; if zero water contamination is mandated, casing is run into the reservoir ahead of the coring section to allow coring with base oil, which leads to smaller core sizes. Additionally, coring operations can require several days when conventional coring technology is applied because of the multitude of necessary trips into and out of the hole. Well engineers applied a systematic approach to achieve new targets by incorporating the latest available technologies and drilling techniques in the industry into a coring program while also optimizing well structural designs by minimizing use of casing strings. This allowed achieving the project's primary objectives of cutting larger-sized cores with no water contamination using minimal planned trips. This paper discusses how managed pressure drilling (MPD) and wellbore strengthening techniques, as well as new coring technologies, were analyzed, planned, and incorporated into this project. This led to the successful execution of an optimized, cost-efficient well structural design with 100% core recovery and no water contamination while. At the same time, a new record was set in terms of the longest core length cut in one run in onshore North America.