In 2019 the operator embarked on a very ambitious data acquisition project in the Bakken, with the goal of mapping far-field drainage and characterizing completion performance. The project consisted of a six-well pad (10,000 ft laterals) with a dedicated observation lateral located in the Three Forks (TF) formation instrumented with cemented pressure gauges and fiber optics along the 10,000 ft lateral. The observation lateral was offset by Middle Bakken (MB) wells ∼450 ft on either side (∼900 ft MB-MB well spacing). One of the MB wells was instrumented with fiber optics for cluster-level completion measurements and "frac hit" detection, while the other offset MB well was used to deploy geophones for microseismic mapping. Three different fracture treatment designs were evaluated, with the goal of understanding how fluid volume & rheology, proppant volume and size, and proppant/fluid ratio affect fracture geometry and drainage. Quantitative application of oil and water tracers was used to evaluate the productivity of each treatment design. During the completions of the first three wells, microseismic data provided important measurements to characterize fracture geometry and "offset well" fiber provided strain data to evaluate fracture morphology (i.e. – far-field fracture behavior). Stress shadowing was evaluated by combining the microseismic and strain data. These measurements were used to calibrate a hydraulic fracture model to enable more reliable predictions of fracture geometry and morphology. Cluster-level measurements of fluid distribution provided data to support increasing clusters/stage and decreasing stage count. Production has been continuously monitored for over 12 months, including interference testing to evaluate connectivity. The pressure gauges placed along the observation lateral provided one of the first-ever measurements of far-field drainage as a function of fracture treatment design (450 ft in between two producing wells, 900 ft well spacing). The results show that MB wells can drain the TF at distances of 450 ft and fracture treatment design can significantly impact drainage and productivity. Although the evaluation, modeling, and trials are ongoing, these results may add significant value by enabling Bakken development with fewer, more productive, wells in some portions of the basin.

The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited.

In 2019, the operator embarked on a very ambitious data acquisition project in the Bakken, with the goal of mapping far-field drainage and characterizing completion performance. The project consisted of a six-well pad (10,000 ft laterals) with a dedicated observation lateral located in the Three Forks (TF) formation instrumented with cemented pressure gauges and fiber optics along the 10,000 ft lateral. The observation lateral was offset by Middle Bakken (MB) wells ~450 ft on either side (~900 ft MB-MB well spacing). One of the MB wells was instrumented with fiber optics for cluster-level completion measurements and “frac hit” detection, while the other offset MB well was used to deploy geophones for microseismic mapping. Three different fracture treatment designs were evaluated, with the goal of understanding how fluid volume and rheology, proppant volume and size, and proppant/fluid ratio affect fracture geometry and drainage. Quantitative application of oil and water tracers was used to evaluate the productivity of each treatment design. During the completions of the first three wells, microseismic data provided important measurements to characterize fracture geometry and “offset well” fiber provided strain data to evaluate fracture morphology (i.e., far-field fracture behavior). Stress shadowing was evaluated by combining the microseismic and strain data. These measurements were used to calibrate a hydraulic fracture model to enable more reliable predictions of fracture geometry and morphology. Cluster-level measurements of fluid distribution provided data to support increasing clusters per stage and decreasing stage count. Production has been monitored continuously for more than 12 months, including interference testing to evaluate connectivity. The pressure gauges placed along the observation lateral provided one of the first-ever measurements of far-field drainage as a function of fracture treatment design (450 ft in between two producing wells with 900 ft well spacing). The results show that MB wells can drain the TF at distances of 450 ft, and fracture treatment design can significantly impact drainage and productivity. Although the evaluation, modeling, and trials are ongoing, these results may add significant value by enabling Bakken development with fewer, more productive wells in some portions of the basin.