SPE 166439 Modeling Water Flow in Hydraulically-Fractured Shale Wells

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SPE 166439 Modeling Water Flow in Hydraulically-Fractured Shale Wells 2016-10-19T10:00:23+00:00

Project Description

SPE 166439 Modeling Water Flow in Hydraulically-Fractured Shale Wells

Wojciech Jakub Jurus (Norwegian University of Science and Technology) | Curtis Hays Whitson (Norwegian University of Science and Technology) | Michael Golan (Norwegian University of Science and Technology)

SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, 30 September-2 October 2013

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This paper provides an approach to model water injection and production performance observed in horizontal multi-fractured wells using a commercial finite difference (FD) model. Stress dependent permeability is used to ensure that injected rates and volumes during hydraulic fracturing are predicted by the FD model. Varying degrees of water retention observed in shale wells is modeled using gas-water imbibition capillary pressure.

Hydraulic fracturing is used to stimulate shale and other ultra-tight reservoirs. During the treatment tens of thousands barrels of water are injected into a single well, distributed between many (5-30+) fractures. Field experience shows that a significant fraction of injected water never flows back, and the amount depends somewhat on how long the well is shut-in prior to production start.

This study was conducted using a commercial black-oil reservoir simulator. A horizontal well with multiple transverse fractures is modeled. A simple stress dependent permeability model (without hysteresis) has been found to provide sufficient permeability increase during injection to ensure the magnitude of injected water rates and volumes achieved during actual fracturing operations.

Inclusion of water imbibition capillary pressures helps control the amount of water retained by the rock after injection. Capillary forces redistribute injected water further into the rock than if capillarity is ignored. When a well is shut-in prior to flowback, imbibition draws injected water yet further into the rock, reducing water mobility and total recovery of injected volumes when the well starts producing. We study water flowback behavior as a function of water imbibition capillary pressure curves: their magnitude and shape (pore size distribution and wettability).

The mobility of water, as given by relative permeability curves, has an impact on water imbibition and distribution of water in the shale formation near the fracture. It affects the rate of water flowback, but it has a limited effect on total water recovery. We also considered situations with the shale formation initially void of water (“dry?? shales), where we find that water recovery is reduced.

Modeling the flow of water in horizontal multi-fractured wells is important to estimate water loss and recovery and the impact on flow performance of hydrocarbons.