Papers by Jean-philippe Nicot
Journal of Hydrology: Regional Studies, Apr 1, 2022
AGU Fall Meeting Abstracts, Dec 1, 2018
AGU Fall Meeting Abstracts, Dec 1, 2016
2015 AGU Fall Meeting, Dec 16, 2015
The Texas Gulf Coast is an attractive target for carbon storage. Stacked sandstone and shale laye... more The Texas Gulf Coast is an attractive target for carbon storage. Stacked sandstone and shale layers provide large potential storage volumes and defense-in-depth leakage protection. Two types of traps are important in the initial sequestration stages: (1) closed structural and stratigraphic traps analogous to oil and gas traps, and (2) open traps where the residual saturation trail of capillary trapping is the main active mechanism. Leakage pathways of primary concern are wellbores and faults. Both could produce a direct connection to the atmosphere. However, most faults do not reach the surface, leaving abandoned wellbores the main focus of a risk analysis. Other leakage pathways, such as a closed trap overflowing through spill points or a seal failure, can be accommodated by the capillary trapping mechanism. The effectiveness of this mechanism depends on the level of heterogeneity of the formations. Determining formation heterogeneity is the second emphasis of any risk analysis in the Texas Gulf Coast. This chapter focuses on the Tertiary section of the Texas Gulf Coast and describes statistics on the hundreds of thousands of boreholes (age, depth, status) drilled in the area and on the shape and size of closed and open traps, which were measured from proprietary structural maps. The chapter also incorporates information about growth-fault distribution and discusses efficiency of capillary trapping. The implications for carbon storage are then derived (e.g., stay away from salt domes and their capture zone; inject mostly deeper than the majority of abandoned wells).
AAPG Bulletin, Oct 1, 2017
Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water c... more Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock-water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock-water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO 4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed
AAPG Bulletin, Jun 1, 2022
GSA 2020 Connects Online, 2020
GSA 2020 Connects Online, 2020
Fluids were collected in a sealed Al container (see Fig. 2) and water pipetted in the lab for IC ... more Fluids were collected in a sealed Al container (see Fig. 2) and water pipetted in the lab for IC (major ions), ICP (trace metals), Sr isotopes, water isotopes analyses. Water samples were centrifuged to eliminate oil droplets
AGU Fall Meeting Abstracts, Dec 19, 2014
2012 NGWA Ground Water Summit: Innovate and Integrate, May 8, 2012
Energy Procedia, 2014
Understanding CO 2 dissolution is significant to the development of CO 2 geological storage. It a... more Understanding CO 2 dissolution is significant to the development of CO 2 geological storage. It allows us to more accurately predict the extent of the CO 2 plume. It also provides a better estimate of the trapping mechanisms to assist in interpreting the monitoring observations and to assess the risk of CO 2 leakage. When CO 2 is injected into methane-saturated brine aquifers, the dissolution process has been observed to be accompanied by CH 4 outgassing from the pore water, which affects the properties of the gas phase and in turn CO 2 migration. Currently available commercial and academic multiphase flow simulators (such as CMG-GEM and TOUGH2) assume instantaneous equilibrium of CO 2 dissolution within a single grid cell, which introduces the maximum amount of dissolution and methane outgassing. The incomplete mixing due to the presence of a porous media and subsurface heterogeneity reduces CO 2 dissolution rates by orders of magnitude compared to the well-mixed case. In this study, we investigate the effects of mixing-controlled CO 2 dissolution and of methane outgassing on CO 2 migration in the subsurface with the help of numerical simulations and laboratory experiments. We first developed numerical pore-scale models to demonstrate that the mass transfer rate of CO 2 depends on the gas saturation and the aqueous CO 2 concentration and that the mass transfer rate can be written as a power-law function of the CO 2 saturation. Based on the mass transfer rate obtained from the pore-scale models, we then simulated the two-phase Darcy's flow in a column test considering the dynamic dissolution process. Results show that the CO 2 migration is affected by the mass transfer rate into the aqueous phase. Even within a small scale of several meters, which is the typical grid size used in simulation of carbon storage in the field, the assumption of instantaneous equilibrium may not be valid. When the mass transfer time scale is much larger than the advection time scale, the CO 2-water flow acts as an immiscible flow, and the amount of CO 2 dissolved within the advection time scale is negligible. As the mass transfer rate increases, the flow approaches the scenario with instantaneous equilibrium. Modeling and experiment presented here confirm the well-known observations that CO 2 dissolution into pore water introduces a retardation effect on CO 2 breakthrough. When the mass transfer rate of CO 2 into pore water increases, the CO 2 breakthrough is delayed, decreasing the extent of the CO 2 plume.
Journal of Unconventional Oil and Gas Resources, Jun 1, 2016
Abstract This study was conducted to document and assess the effects of fluid–rock interactions w... more Abstract This study was conducted to document and assess the effects of fluid–rock interactions when CO2 is used to create the fractures necessary to produce hydrocarbons from low-permeability rocks. The primary objectives are to (1) identify and understand the geochemical reactions of CO2-based fracturing, and (2) assess potential changes in porosity and permeability of formation rock. Autoclave experiments were conducted at reservoir conditions exposing middle Bakken core fragments to CO2-saturated synthetic formation brine and to supercritical CO2 (sc-CO2) only. Ion-milled core samples were examined before and after the reaction experiments using scanning electron microscopy (SEM), which enabled us to image the reaction surface in extreme detail and unambiguously identify mineral dissolution and precipitation. The most significant change in the reacted samples exposed to the CO2-saturated brine is dissolution of the carbonate minerals, particularly calcite, which shows severe corrosion. Dolomite grains were corroded to a lesser degree. Quartz and feldspars remained intact, and some pyrite framboids underwent slight dissolution. Additionally, a small amount of calcite precipitation took place, as indicated by numerous small calcite crystals formed at the reaction surface and in the pores. The changes of aqueous chemical composition are consistent with the petrographic observations with an increase in Ca and Mg and associated minor elements, and a very slight increase in Fe and sulfate. When exposed to sc-CO2 only, changes observed include etching of the calcite grain surface and precipitation of salt crystals (halite and anhydrite) due to evaporation of residual pore water into the sc-CO2 phase. Dolomite and feldspars remained intact, and pyrite grains were slightly altered. Mercury intrusion capillary pressure (MICP) tests on reacted and unreacted samples show an increase in porosity when an aqueous phase is present but no overall porosity change with sc-CO2. The results also show an increase in permeability for brine-reacted samples.
AGU Fall Meeting Abstracts, Dec 1, 2019
2015 AGU Fall Meeting, Dec 16, 2015
2012 GSA Annual Meeting in Charlotte, 2013
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Papers by Jean-philippe Nicot