Search

Changes in pore (throat) size, surface roughness, and mineralogy induced by supercritical CO2‐water‐rock reactions impact petrophysical properties such as porosity, permeability, and especially wettability. Herein, we show that these changes directly impact relative permeability and capillary pressure curves, a fact rarely studied in the literature. In this work, we show that CO2 contact angle changes emerge after Madison Limestone samples were soaked for 400 hr in CO2‐enriched brine. Coreflooding results show that the water production rate and cumulative water production increased after the rock was exposed to carbonic acid. Moreover, the mercury capillary pressure decreased in mesopores and macropores, indicating the increase of size in these pores due to reactions. This compounded wettability and pore network alteration can directly affect CO2 injectivity, migration, and storage capacity. This fundamental insight into CO2 geological storage processes should aid practitioners to reduce uncertainties in forecasting CO2 distribution via injection simulation. Plain Language Summary: Emitting a large amount of greenhouse gases into the atmosphere has disrupted the global carbon cycle. CO2 captured from various sources could be transported to a close‐by site for injection into deep saline aquifers or oil/gas reservoirs for storage or/and enhanced oil recovery. Reactions between the rock and the carbonic acid can alter the rock fabric. These reactions can change rock properties, for example, pore structure, porosity, permeability, and wettability. These changes can affect capillary pressure and relative permeability. These rock alterations can significantly impact the fate of the injected CO2. Despite efforts made to determine changes in pore architecture or petrophysical properties, a few studies have investigated the impact of rock alteration on multiphase flow properties, namely, capillary pressure and relative permeability. Even less is understood on this subject when diffusion dominates over convective transport. Here we focused on changes in pore (throat) size distribution and wettability, and dynamic properties, as induced by geochemical reactions. We observed pore enlargement among the larger pores (mesopores to macropores) due to mineral dissolution, which contrasts with a decreased size in smaller pores (micropores), resulting from mineral precipitation. These processes lead to a more CO2 surface wetting and thereby capillary pressure and relative permeability. Key Points: CO2‐brine‐rock reactions at reservoir conditions improve CO2 wettabilityGeochemical reactions alter the rock pore architecture and multiphase flow responseMultiphase flow alterations correlate well with changes in wettability and pore structure [ABSTRACT FROM AUTHOR]

Laboratory experiments evaluated two shale caprock formations, the Gothic Shale and Marine Tuscaloosa Formation, at conditions relevant to carbon dioxide (CO2) sequestration. Both rocks were exposed to CO2-saturated brines at 160°C and 15 MPa for ∼45 days. Baseline experiments for both rocks were pressurized with argon to 15 MPa for ∼35 days. Varying concentrations of iron, aqueous silica, sulfate, and initial pH decreases coincide with enhanced carbonate and silicate dissolution due to reaction between CO2-saturated brine and shale. Saturation indices were calculated and activity diagrams were constructed to gain insights into sulfate, silicate, and carbonate mineral stabilities. Upon exposure to CO2-saturated brines, the Marine Tuscaloosa Formation appeared to be more reactive than the Gothic Shale. Evolution of aqueous geochemistry in the experiments is consistent with mineral precipitation and dissolution reactions that affect porosity. This study highlights the importance of tracking fluid chemistry to clarify downhole physicochemical responses to CO2 injection and subsequent changes in sealing capacity in CO2 storage and utilization projects. [ABSTRACT FROM AUTHOR]

The Thermopolis hydrothermal system is located in the southern portion of the Bighorn Basin, in and around the town of Thermopolis, in northwest Wyoming. It is the largest hydrothermal system in Wyoming outside of Yellowstone National Park. The system includes hot springs, travertine deposits, and thermal wells. Published models for the hydrothermal system propose the Owl Creek Mountains as the recharge zone, simple conductive heating at depth, and resurfacing of thermal waters up the Thermopolis Anticline. The geochemistry of the thermal waters of three active hot springs--Big Spring, White Sulphur Spring, and Teepee Fountain--is similar in composition and characteristic of carbonate or carbonate-bearing siliciclastic aquifers. Previous studies of the Thermopolis hydrothermal system postulate that the thermal waters are a mixture of waters from Paleozoic formations. Major element geochemical analyses available for waters from these formations are not of sufficient quality to determine whether the thermal waters are a mixture of the Paleozoic aquifers. In the time frame of this study (one year), the geochemistry of all three springs was constant through all four seasons, spanning spring snowmelt and recharge as well as latesummer and fall dryness. This relationship is consistent with a deep source not influenced by shallow, local hydrogeology. Anomalies are evident in the historic data set for the geochemistry of Big Spring. We speculate that anomalies occurring between 1906 and 1926 suggest mixing of source waters of Big Spring with waters from a siliciclastic formation, and that anomalies occurring between 1926 and 1933 suggest mixing with waters from a formation containing gypsum or anhydrite. Decreased concentrations measured in our study-- relative to concentrations measured between 1933 and 1976--may reflect mixing of thermal waters with more dilute waters. Current data are not sufficient to rigorously test these suggestions, and events of sufficient scale taking place in these timeframes have not been identified. [ABSTRACT FROM AUTHOR]

Abstract: The potential impact to the integrity of wellbore cements as a result of exposure to supercritical carbon dioxide (SCCO2) has been raised as an area of some concern with respect to long-term effectiveness of CO2 storage in geological formations. In flow-through experiments we simulated diffusion of brine and SCCO2 from the interface between wellbore cement and caprock into a fracture-bearing Portland cement. The experiments were performed at in-situ reservoir pressure (pore pressure: 19.9 MPa) and temperature (54 °C) conditions for 113 days. For this purpose we saturated illite-rich shale and the Portland cement core (2.02 cm×5.35 cm) with 1.65 M brine for 14 days. After this period of time we injected SCCO2 into the system for 99 days and simulated a diffusion process by using a pressure gradient of 0.7 MPa. Calcite precipitation occurred within the fracture and the induced pressure of crystal growth may explain an increase in the relative permeability along the fracture with time. SCCO2-induced reactions extended ~5 mm into the Portland cement core from the fracture and formed an orange-colored zone. The orange-colored zone is nearly completely carbonated with crystalline phases consisting mainly of calcite, aragonite, and vaterite. The only crystalline cement component that persisted in the orange-colored zone was brownmillerite. Interior portions of the hydrated cement were partially carbonated, modified in texture and contained newly formed calcite, hydrogarnet and hydrocalumite (Friedel''s salt). Cement porosity decreased from 37.8% to 23.8% during carbonation and was associated with a 19.6% increase in mass. [Copyright &y& Elsevier]

Water-based hydraulic fracturing requires high-pressure injection of large quantities of water mixed with chemicals into the subsurface, where fluids contact mineral surfaces. Chemical imbalance between minerals and the injected fluids provides the potential for chemical reactions that may induce physical alterations to the rock. We investigate mineral reactivity during in situ water-rock interaction between unconventional reservoir rocks and hydraulic fracturing fluid. We characterized two unconventional reservoir rocks, a calcareous mudstone (B Bench of the Niobrara Formation) and a calcite-cemented sandstone (Wall Creek Member of the Frontier Formation) of the Powder River Basin, Wyoming, USA, and developed, analyzed, and quantified the aqueous geochemistry of a hydraulic fracturing fluid (HFF). These datasets informed the design of numerical simulations that predict mineral-HFF interactions at in situ conditions over a 31-day timeframe. The two unconventional reservoir rocks have similar mineral assemblages, albeit in different proportions, which leads to similar dissolution/precipitation reactions. Calcite, feldspar, and authigenic clay minerals begin to dissolve, and secondary calcite, anhydrite, and illite form. Calcite dissolution increases porosity of the B Bench from 2% to 2.9% and porosity of the Wall Creek from 5% to 5.8%. Mineral-fluid reactions manifest in flowback fluids as temporal geochemical trends consistent with limited field data. • Two target rocks have similar mineral assemblages albeit in different proportions. • Calcite and aluminosilicates dissolve; a secondary aluminosilicate and calcite form. • Calcite dissolution significantly increases porosity of both rocks. • Simulated fluid chemistry is consistent with limited data collected in the field. • Aqueous SiO 2 , Mg, and pH correlate with the behavior of aluminosilicate minerals. [ABSTRACT FROM AUTHOR]