Exploration and structural controls of the McGinness Hills geothermal field

Abstract

Exploration and commercial operation of the McGinness Hills geothermal complex was successfully achieved in two phases of development from 2007-2012 (30 MWe net) and from 2012-2015 (72 MWe total net). Each binary power plant accommodates ~12,000 gpm of fluids at temperatures of 337oF which have remained constant. The geothermal system is situated within an intermountain fault-bounded shallow sedimentary basin in the Toiyabe Mountains of central Nevada and within the Basin and Range Physiographical province. Prior to any geothermal exploration here, from ~1980 through 2005, mineral prospectors were attracted by extensive siliceous sinter deposits, associated veining paragenesis, and distribution of various alteration facies although no economic concentrations of metals were discovered. During geothermal exploration, five NNE-striking WNW-dipping faults which overlap and step left were identified which host the reservoir at depth and associate with the sinter deposits and alteration facies at the surface. These faults intersect laterally with other ENE- and NW-striking faults and at depth with other NE-striking faults that dip SE. Stress field vectors derived from downhole induced fractures and breakouts indicate that the NNE-striking faults should be oriented favorably for dilation. Ten production wells in the north feed from fractures in both a Tertiary intrusive monzonite and Ordovician quartzite, and six injection wells in the south have feed zones hosted in Ordovician quartzite. All wells exhibit high permeabilities (>2800 md and productivity indexes from 47 to >1000 gpm/psi). Rapid hydraulic pressure communication between northern and southern wells that feed to widely separated faults generated initial concerns for potential rapid return of injected fluid to production wells. In the initial development phase, understanding the hydraulic connection was key to also understanding the geologic structure and determining commercial feasibility. To better understand the reservoir and qualify for a project release, extensive wellfield testing was performed and a reservoir simulation was utilized that assumed lateral hydraulic connection between faults and associated well feedzones. During operation of plant 1, a tracer test was conducted and resulted in long durations for initial tracer returns to production (~40 days) with relatively low peak concentrations (≤5 ppb). As a result a geologic model was adopted which integrated deeply connected fluid pathways that are controlled by deep intersections of antithetic NNE- to NE-striking faults. Per the revised geologic model, the geothermal system is contained within a NNE trending graben system which is ~5 miles in length and thermal fluids preferentially ascend along the eastern margin. The deep connection of fluid pathways between production and injection allows for mixing and deep extraction of heat. A second tracer study conducted during operation of both power plants produced results similar to the first and further elucidated the nature of the deeply connected fluid pathways.

AAPG Datapages/Search and Discovery Article #90266 © 2016 AAPG Pacific Section and Rocky Mountain Section Joint Meeting, Las Vegas, Nevada, October 2-5, 2016