GSA Annual Meeting in Phoenix, Arizona, USA - 2019

Paper No. 300-6
Presentation Time: 2:45 PM


GARDINER, James1, THOMAS, R. Burt2, PHAN, Thai T.3, STUCKMAN, Mengling4, LOPANO, Christina L.5 and HAKALA, J. Alexandra5, (1)Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA 15236; LRST, Pittsburgh, PA 15236, (2)Department of Energy, National Energy Technology Laboratory, Albany, OR 97321; LRST, Albany, OR 97321, (3)Department of Earth and Environmental Sciences, University of Waterloo, Waterloo, ON N2L 3G1, Canada; Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA 15236, (4)LRST, Pittsburgh, PA 15236; Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA 15236, (5)Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA 15236

Produced water from CO2 enhanced oil recovery (EOR) formations provides an opportunity to study how CO2 injection impacts geologic formations and their fluids. These fluids provide insights into geochemical reactions that will affect storage capacity, injectivity, and storage verification.

Produced water from an oilfield in the Permian Basin and overlying groundwaters were monitored from June 2013-April 2018 as the field transitioned from water injection to CO2 water-alternating-gas (WAG) recovery. These data are used to evaluate the criteria for baseline geochemical conditions in oil fields with changing well stimulation practices. The baseline concept is important to (1) monitor the produced water for variations that reflect reservoir dissolution-precipitation reactions and (2) determine which geochemical signals are reflective of produced water intrusion into overlying groundwaters.

Produced water was sampled from the Upper San Andres Fm., a dolomite reservoir (~1630 m); overlying groundwaters were sampled from the Ogallala (~50 m) and Santa Rosa (~460 m) formations. This field was sampled once prior to CO2 injection and seven times during CO2-WAG operations. Following CO2 injection, there were increases in certain produced water analytes [alkalinity, TDS, Na+, Cl-, and SO42-] and no significant changes in other variables [pH, Ca2+, and Mg2+]. Fresh groundwaters did not demonstrate any observable changes.

Results from this study were compared with pre-waterflooding samples from previous research. Provided with this historical context, the effects of waterflooding and CO2 injection were identified. Additionally, this study applied saturation indices and isometric log-ratio (ilr) transformations to field samples. The extrapolated information was utilized to (1) identify CO2 induced chemical reactions within the target formation and (2) determine if a produced water baseline could be identified given the changing oil field practices. This study shows that the concentrations fluctuated with changing oil field practices, but saturation indices and ilr coordinates were unchanged. These results served to determine (1) reservoir stability during CO2 injection and (2) that ilr coordinates can be used as a baseline metric at this field site. Additionally, the produced water ilr coordinates were distinct from overlying Santa Rosa formation and can be used to detect produced water intrusion.