Estimation of fracture height growth in layered tight/shale gas reservoirs using flowback gas rates and compositions–Part II: Field application in a liquid-rich tight reservoir

• Published in: Journal of natural gas science and engineering 2016-11, Vol.36, p.1031-1049
• Main Authors: Clarkson, C.R., Ghaderi, S.M., Kanfar, M.S., Iwuoha, C.S., Pedersen, P.K., Nightingale, M., Shevalier, M., Mayer, B.
• Format: Article
• Language: English
• Subjects: Flowback; Fracture height; Geochemistry; Hydraulic fracturing; Layered reservoirs; Liquid-rich tight gas reservoir; Liquid-rich tight reservoir
• ISSN: 1875-5100
• DOI: 10.1016/j.jngse.2016.11.014

While hydraulic fracturing is the key to unlocking the potential of unconventional low-permeability hydrocarbon resources, challenges remain in the monitoring of subsurface propagation of fractures and the determination of which geologic intervals have been contacted. This is particularly challenging for wells that are completed in multiple hydraulic fracture stages (multi-fractured horizontal wells or MFHWs) where fracture spacing may be very close and fracture geometry complex. Understanding the fracture extent is important not only for assisting with hydraulic fracture design, but also for mitigating unwanted fracture growth into non-target geologic intervals that do not contain hydrocarbons (e.g. zones with high water saturation). Popular current technologies used for hydraulic fracture surveillance include microseismic (surface and subsurface monitoring) and tiltmeter surveys. While these methods have proven useful for characterizing the extent of created hydraulic fractures, they do not necessarily lead to an understanding of what portions of the geologic section (bounding and target intervals for MFHWs, for example) are in direct hydraulic communication with the well. A solution for establishing the extent of hydraulic fracture growth from target to bounding zones is to first obtain a fluid composition fingerprint of those intervals while drilling through them, and then compare these data with fluid compositions obtained from flowback after hydraulic fracturing. In the current work, a MFHW completed in a liquid-rich tight reservoir is used to test this novel concept. Gas samples extracted from the headspace of isojars® containing cuttings samples, obtained during drilling of the MFHW well, were used to geochemically fingerprint geologic intervals through which the well was drilled. The cuttings samples were collected at high frequency in the vertical, bend and lateral sections of the well over a measured depth range of 4725 ft (1440 m). A compositional marker was identified in the bend of the horizontal well above which the average methane to ethane (C1/C2) ratio was 15.7, versus 2.6 below it. The flowback gas compositions were observed to be intermediate (average C1/C2 = 7.4) between the reservoir above and below the marker, suggesting fracture height grew above the compositional marker. In order to estimate fracture height growth from the geologic interval and flowback compositions, a compositional numerical simulation study was performed. An inno