Reservoir Geology of the Montney Formation from analysis of flowback and produced fluids, petrophysics and lithofacies analyses

Marc Bustin, Ph.D., P. Geol., FRSC University of British Columbia, Department of Earth, Ocean and Atmospheric Sciences

September 18, 2018

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ABSTRACT 
Detailed analysis of fluids and solids mineralogy and fabric from flowback waters from fifty Montney Formation horizontal well completions in Western Canada, when coupled with petrophysical and lithological analysis of core, provides insights into the reservoir geology, which in turn enables strategies for optimising well completions, production, and well surveillance. 

The chemistry and volume of flowback fluids following well completions is a complex product of the mixing of connate water and completion fluid and fluid-rock interactions that includes precipitation and dissolution of minerals, ion exchange, imbibition, and diffusion/osmosis.  In general, the chemistry and volume of flowback waters from Montney completions varies with the completion program, reservoir lithofacies, depth of burial, and hence geographically and stratigraphically.  In detail; however, the flowback volume and chemistry varies with a plethora of variables most of which have multicollinearity.  These variables include, completion fluid chemistry, number of stages, shut-in time, surface area of the fracture network/stimulated reservoir volume, length of flowback period, connate water chemistry, and ambient stress field. 

The cumulative volume of flowback fluid from Montney completions ranges from about 15% to 30% of the volume injected.  The proportion of connate water in the flowback water, based on conserved element and isotope analyses, varies from about 10% to 60%, and the proportion of connate water increases with time of flowback.  The total dissolved solids (TDS) of Montney flowback fluids range up to 230 000 mg/L, with Cl and Na ions accounting for about 75% to 95% of the total dissolved solids.  Other major ions are Ca, K, Mg, Sr, and locally SO4.  With cumulative flowback, the TDS and most ions, for all wells, increases linearly, although the rate of increase varies between wells, and with stratigraphy, lithofacies (parasequence), and geographic area.  Deviation from the linear increase in TDS and conserved elements with cumulative flowback, reflects opening or closing of the fracture system(s) with declining pore pressure, variation in connate water chemistry and reservoir geology along laterals, and/or fractures that have grown out of zone. Geochemical modeling also indicates that the ions that deviate from the linear mixing model are impacted by fluid-rock interactions including precipitation, dissolution, and/or ion exchange reactions.  Reservoir surveillance using geochemical models coupled with analysis of the flowback and produced fluids provide a means of predicting and mitigating against salting and scaling in the reservoir, due to dehydration of saline connate water during gas production.

The mechanics of mixing between completion fluid and connate water is complex and poorly understood.  Analysis of connate water and fluid saturations indicate that most of the unconventional Montney Formation is below irreducible water saturation.  Yet the isotopic data indicates that a significant proportion of the flowback is connate water, even though the total volume of water recovered is generally much less than 30% of the total volume injected.  Imbibition experiments and measures of wettability indicate the Montney has mixed wettability, but is preferentially oil wet.  The spontaneous and forced imbibition/osmosis of drilling and completion fluids results in significant fracture skin damage, resulting in a decreased relative matrix permeability by up to two orders of magnitude.  In addition, the imbibed completion fluid, depending on composition, may weaken and ‘soften’ the fracture face promoting proppant embedment, early collapse of non-propped fractures, and creation of fines, which in turn may plug the proppant pack and stabilise emulsions. 

The variably large proportion of completion fluid remaining in the reservoir after flowback is a product of the low initial reservoir water saturation, the increase in capillary pressure of imbibed completion fluids due to fluid-rock interactions, and much lower differential pressure during flowback than during completions.

BIOGRAPHY 


R. Marc Bustin is a Professor in the Department of Earth and Ocean Sciences at the University of British Columbia and president of RMB Earth Science Consultants. Bustin received his BSc and M.Sc. degrees from the University of Calgary and his PhD from the University of British Columbia.

Bustin is an elected Fellow of the Royal Society of Canada and a registered professional geologist in the province of British Columbia.