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.
Until recently, microseismic has been the primary diagnostic for estimating "bulk" or stage-level fracture geometry, including asymmetry due to parent-child interactions, for modern multi-cluster plug-and-perf completions. However, microseismic cannot provide details on individual fractures or cluster-level measurements. With the continued advances in fiber optic technologies, we can now measure cluster level fracture behavior at the wellbore and in the far-field. Characterizing the relationship between wellbore and far-field fracture geometry, referred to as fracture morphology, is important when simultaneously optimizing completion design and well spacing. Microseismic and fiber optics are very robust, but expensive, technologies and this limits the frequency of their application. Recently developed low-cost pressure-based technologies enable high-volume data acquisition but may not provide the same level of detail compared to microseismic and fiber optic measurements. This paper presents a case history that details the application of deployable fiber optics to characterize fracture geometry and morphology using microseismic and strain data. The paper also presents results from Sealed Wellbore Pressure Monitoring (SWPM) (Haustveit et al. 2020), comparing the lower-cost SWPM technology to the higher-cost deployable fiber. Wireline-fiber was deployed in the inner two wells, one Middle Bakken (MB) and one Three Forks (TF), of a four-well pad. Surface pressures were recorded on all wells on the pad and nearby parent wells. The outer two wells, one MB and one TF, were completed first, using zipper operations. Fiber-based microseismic and strain measurements were used to characterize fracture geometry and morphology, and parent-child interactions. Pressure measurements on the two inner wells were used for SWPM, providing estimates of completion effectiveness and fracture geometry using Volume to First Response (VFR) measurements. The microseismic data showed asymmetric growth from the eastern well to the parent well pad, with fractures covering the entire parent well pad. More symmetric fracture growth was measured for the western well, as the parent well pad was farther away. The microseismic data provided fracture geometry measurements consistent with previous measurements in the same area using a geophone array. The SWPM results compared favorably to the fiber measurements using the high confidence data. However, there were data acquisition complexities with both technologies that will be detailed in the paper. Fiber strain measurements provided detailed information on fracture morphology, showing significant decreases in the number of far-field hydraulics as distance increases from the completion well. The advancements in Low Frequency Distributed Acoustic Sensing (Ugueto et al. 2019) provides the ability to monitor hydraulic fractures approaching, passing above/under, and intersecting the monitoring location. Both fiber and SWPM showed much faster fracture growth within the same formation compared to fracture growth between formations. The integration of the fiber optic measurements and SWPM results have provided important insights into fracture geometry and morphology, leading to improved hydraulic fracture models.
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.
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