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.