Estimates of lithium mass yields from produced water sourced from the Devonian-aged Marcellus Shale.

Decarbonatization initiatives have rapidly increased the demand for lithium. This study uses public waste compliance reports and Monte Carlo approaches to estimate total lithium mass yields from produced water (PW) sourced from the Marcellus Shale in Pennsylvania (PA). Statewide, Marcellus Shale PW has substantial extractable lithium, however, concentrations, production volumes and extraction efficiencies vary between the northeast and southwest operating zones. Annual estimates suggest statewide lithium mass yields of approximately 1160 (95% CI 1140-1180) metric tons (mt) per year. Production decline curve analysis on PW volumes reveal cumulative volumetric disparities between the northeast (median = 2.89 X 107 L/10-year) and southwest (median = 5.56 × 107 L/10-year) regions of the state, influencing lithium yield estimates of individual wells in southwest [2.90 (95% CI 2.80-2.99) mt/10-year] and northeast [1.96 (CI 1.86-2.07) mt/10-year] PA. Moreover, Mg/Li mass ratios vary regionally, where NE PA are low Mg/Li fluids, having a median Mg/Li mass ratio of 5.39 (IQR, 2.66-7.26) and SW PA PW is higher with a median Mg/Li mass ratio of 17.8 (IQR, 14.3-20.7). These estimates indicate substantial lithium yields from Marcellus PW, though regional variability in chemistry and production may impact recovery efficiencies.

Dataset documenting reaction-induced changes to five fractured foamed wellbore cement cores during CO2 fluid flow.

The integrity of wellbore cement is vital for the long-term success of applications such as enhanced oil recovery and carbon storage. Intact cemented well casings are crucial to preventing leakage and fluid migration, as well as maintaining safety of operations. To investigate the changes to fractures in foamed wellbore cement in a carbon storage scenario, four cores were fractured lengthwise and injected with deionized water at equilibrium with CO2. The experiment duration was five days for the first core and was increased for each successive test, with the final test lasting 20 days. The fractured cores were periodically imaged with a NorthStar M5000 Industrial Computed Tomography (CT) scanner, documenting the changes to the fracture during dissolution, as well as the reaction zone in the surrounding cement matrix. For two cores with the most robust reactions, the fracture and two reaction zones (proximal and distal to the fracture) were segmented from the raw CT data. They were quantified volumetrically and in the form of fracture aperture maps. A Local Cubic Law (LCL) modeling suite was used to map out localization of flow within the open portions of the fractures.

Alteration of Fractured Foamed Cement Exposed to CO2-Saturated Water: Implications for Well Integrity.

Geologic CO2 storage (GCS) is a method to mitigate the adverse impact of global climate change. Potential leakage of CO2 from fractured cement at the wellbore poses a risk to the feasibility of GCS. Foamed cement is widely applied in deepwater wells where fragile geologic formations cannot support the weight of conventional cement. Thus, it is critical to know whether fractures in foamed cement self-seal in a similar manner as conventional cement systems. This study is the first to investigate the changes in physical and chemical attributes of foamed cement under dynamic flow conditions using CO2-saturated water. Self-sealing of fractures in the cement was observed at a solution flow rate of 0.1 mL/min and a pressure of 6.9 MPa. The formation of CaCO3 precipitates in pore spaces and fractures led to a decrease in permeability by 1 order of magnitude. The extents of self-sealing in foamed cement samples, specifically the 20 and 30% air volume formulations, were similar to that of conventional cements. We attribute this to the greater alteration depth in the foamed cement, which compensated for the reduced availability of Portlandite and higher initial porosity. The results can be used to evaluate the risk of leakage associated with foamed cement.

Shale pore alteration: Potential implications for hydrocarbon extraction and CO2 storage.

Shale unconventional reservoirs are currently and expected to remain substantial fossil fuel resources in the future. As CO2 is being considered to enhance oil recovery and for storage purposes in unconventional reservoirs, it is unclear how the shale matrix and fractures will react with CO2 and water during these efforts. Here, we examined the Utica Shale and its reactivity with CO2 and water using scanning electron microscopy, N2 and CO2 sorption isotherms, mercury intrusion porosimetry, and X-ray scattering methods. During CO2 exposure, the presence of water can inhibit CO2 migration into the shale matrix, promote carbonate dissolution, and dramatically change the pore scale variability by opening and closing pore networks over the macro- to nano-scale range. These alterations in the shale matrix could impact flow pathways and ultimately, oil recovery factors and carbon storage potential.

CO2 reaction with hydrated class H well cement under geologic sequestration conditions: effects of flyash admixtures.

The rate and mechanism of reaction of pozzolan-amended Class H cement exposed to both supercritical CO2 and CO2-saturated brine were determined under geologic sequestration conditions to assess the potential impact of cement degradation in existing, wells on CO2 storage integrity. The pozzolan additive chosen, Type F flyash, is the most common additive used in cements for well sealing in oil-gas field operations. The 35:65 and 65:35 (v/v) pozzolan-cement blends were exposed to supercritical CO2 and CO2-saturated brine and underwent cement carbonation. Extrapolation of the carbonation rate for the 35:65 case suggests a penetration depth of 170-180 mm for both the CO2-saturated brine and supercritical CO2 after 30 years. Despite alteration in both pozzolan systems, the reacted cement remained relatively impermeable to fluid flow after exposure to brine solution saturated with CO2, with values well below the American Petroleum Institute recommended maximum well cement permeability of 200 microD. Analyses of 50: 50 pozzolan-cement cores from a production well in a sandstone reservoir exhibited carbonation and low permeability to brine solution saturated with CO2, which are consistent with our laboratory findings.

Rate of CO2 attack on hydrated Class H well cement under geologic sequestration conditions.

Experiments were conducted to study the degradation of hardened cement paste due to exposure to CO2 and brine under geologic sequestration conditions (T = 50 degrees C and 30.3 MPa). The goal was to determine the rate of reaction of hydrated cement exposed to supercritical CO2 and to CO2-saturated brine to assess the potential impact of degradation in existing wells on CO2 storage integrity. Two different forms of chemical alteration were observed. The supercritical CO2 alteration of cement was similar in process to cement in contact with atmospheric CO2 (ordinary carbonation), while alteration of cement exposed to CO2-saturated brine was typical of acid attack on cement. Extrapolation of the hydrated cement alteration rate measured for 1 year indicates a penetration depth range of 1.00 +/- 0.07 mm for the CO2-saturated brine and 1.68 +/- 0.24 mm for the supercritical CO2 after 30 years. These penetration depths are consistent with observations of field samples from an enhanced oil recovery site after 30 years of exposure to CO2-saturated brine under similar temperature and pressure conditions. These results suggest that significant degradation due to matrix diffusion of CO2 in intact Class H neat hydrated cement is unlikely on time scales of decades.

Degradation of well cement by CO2 under geologic sequestration conditions.

Experiments were conducted to assess the durability of cements in wells penetrating candidate formations for geologic sequestration of CO2. These experiments showed a significant variation in the initial degradation (9 days of exposure) based on the curing conditions. The high-temperature (50 degrees C) and high-pressure (30.3 MPa) curing environment increased the degree of hydration and caused a change in the microstructure and distribution of the Ca(OH)2(s) phase within the cement. Cement cured at 50 degrees C and 30.3 MPa (representing sequestration conditions) proved to be more resistant to carbonic acid attack than cement cured at 22 degrees C and 0.1 MPa. The cement cured at 50 degrees C and 30.3 MPa exhibited a shallower depth of degradation and displayed a well-defined carbonated zone as compared to cement cured under ambient conditions. This is likely due to smaller, more evenly distributed Ca(OH)2(s) crystals that provide a uniform and effective barrier to CO2 attack.