Influence of Hyper-Alkaline pH Leachate on Mineral and Porosity Evolution in the Chemically Disturbed Zone Developed in the Near-Field Host Rock for a Nuclear Waste Repository

This paper evaluates the effect of hyper-alkaline (NaOH/KOH) leachate on the mineralogy and porosity of a generic quartzo-feldspathic host rock for intermediate- and low-level nuclear waste disposal following permeation of the cementitious repository barrier by groundwater. The analysis is made with reference to expected fluid compositions that may develop by contact of groundwater with the cementitious barrier to form a chemically disturbed zone (CDZ) in the adjacent host rock, as informed by relevant natural analogue sites. Theoretical analysis and numerical modelling is used to explore the influence of different host rock mineral assemblages on changes in pore fluid chemistry, multiple mineral dissolution and precipitation reactions and matrix porosity within the CDZ under these conditions. The numerical modelling accounts for kinetic and surface area effects on the mineral transformation and porosity development for periods of up to 10,000 years travel time from the repository and ambient temperature of 20∘C. The analysis shows that dissolution of quartz, feldspar and muscovite in the host rock, by the hyper-alkaline waste leachate, will create relatively high concentrations of dissolved Si and Al in the pore fluid, which migrates as chemical fronts within the CDZ. Precipitation of secondary mineral phases is predicted to occur under these conditions. The increase in matrix porosity that arises from dissolution of primary aluminosilicate minerals is compensated by a reduction in porosity due to precipitation of the secondary phases, but with a net overall increase in matrix porosity. These coupled physical and geochemical processes are most important for contaminant transport in the near-field zone of the CDZ and are eventually buffered by the host rock within 70 m of the repository for the 10,000 year travel time scenario. The predicted changes in matrix porosity may contribute to increased transport of radionuclides in the host rock, in the absence of attenuation by other mechanisms in the CDZ

Characterization of Partially Formed Polymer Gels for Application to Fractured Production Wells for Water-Shutoff Purposes

Abstract A laboratory study was conducted to characterize watershutoff polymer gels that are injected in the partially formed (partially matured) state into fractures (or other high permeability anomalies) that are in direct contact with production wells. Partially formed (<8-hr-old) 1X (0.5% polymer) chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels showed much lower (as much as 100 times less) effective viscosities (17 to 30 cp) during placement in a 1-mm-wide fracture than "fully formed" (>15-hr-old) gels with the same chemical composition. Thus, partially formed gels exhibit substantially higher injectivities and lower placement pressures. This feature is of major importance during field applications where pressure constraints limit rates and volumes during gel injection. For gelants and partially formed gels that were 5 hours old or less, the rates of gelant leakoff through fracture faces were very low [about 0.013 ft . Thus, field applications that inject relatively small volumes of gelant or partially formed gels will generally experience small gelant leakoff distances, and the leakoff substance will not significantly inhibit oil from entering the fractures. During first brine injection after gel placement and maturation in 1-mm-wide fractures, the pressure gradient required to first breach the gel increased significantly with increasing polymer concentration in the gel -ranging from roughly 5 psi/ft for 1X (0.5% polymer) partially formed gels to 99 psi/ft for 3X (1.5% polymer) partially formed gels. For 1X gels, the breaching pressure gradient was greatest (~9 psi/ft) when the gel was aged from 12 to 24 hours before injection. Prior to exceeding the breaching pressure gradient, no detectable brine flowed through the fracture. During the limited brine flow after gel placement, most (>90%) of the gel remained in the fracture and did not "washout." The stabilized residual resistance factors (permeability reduction factors) for the first brine flood through the fracture (following gel placement and maturation) ranged from 750 to 22,000 -increasing with increasing polymer concentration and gel strength. The large stabilized (final and equilibrium) residual resistance factors for brine flow through the gel-filled fracture resulted from the brine flow occurring through relatively small channels (wormholes) residing in the gel. For the 1X gel, the stabilized permeability reduction factors (for brine flow in a gel-treated fracture) were comparable for formulations injected in the gelant state, the partially formed state, and the "fully formed" state. The CC/AP gels exhibited disproportionate permeability reduction during brine and oil flow through gelfilled fractures. During one experiment with the 1X gel, brine permeability in the fracture was reduced 166 times more than that for oil. In this case, brine was flooded first, followed by oil. For the 1X and 3X gels, the permeability reduction factor for oil flow remained constant (within experimental error) during four cycles of brine and oil injection. In contrast, the permeability reduction factor for brine decreased more than a factor of 10 during these cycles. Introduction During this laboratory study, we characterized water-shutoff polymer gels of the type that are to be injected in the partially formed state into fractures which are connected to production wells. Findings of this study should also be relevant to other high-permeability anomalies that are connected to petroleum production wells. Other than fractures, these high-permeability anomalies could include solution channels, interconnected vugs, karsted features, joints, faults, rubblized zones, and ultra-high matrix rock permeability. These features generally have permeabilities greater than two darcies. For water-shutoff applications in fractured production wells (i.e., during field applications), injected polymer gels are usually in the partially formed state during transit from the wellbore into the formation. For classical bulk gel treatments applied to reservoir fractures, the injected polymer-gel solution should develop enough gel structure (including microgel structure) to minimize detrimental gel solution leakoff into the matrix reservoir rock that is adjacent to the fractures. On the other hand, the gel should not be fully formed during placement because excessive injection pressures may be encountered. Use of partially formed gel