A comparison of a simple model of EUV dayglow with Viking data

Bibliography: p. 73-79

Monitoring the reservoir geochemistry of the Pembina Cardium CO2 monitoring project, Drayton Valley, Alberta

AbstractThe Pembina Cardium CO2 Monitoring Project in central Alberta was built to assess the Cardium formation’s storage potential for CO2 and stimulate oil production. Three baseline trips and 28 monitoring trips were undertaken over a three year period from February 2005 to March 2008 to collect fluids and gas from eight producing wells. Chemical and isotope analyses were conducted on the fluid and gas samples to determine the changes in the geochemistry of the pilot area and to assess the fate of the injected CO2. It was found that within 67 days after commencement of CO2 injection, injection CO2 break-through occurred in four of the eight monitoring wells. Further, CO2 dissolution was observed in three of the four monitoring wells in this time frame and in one well, 12–12, both CO2 dissolution and calcite mineral dissolution were observed within 67 days of the onset of CO2 injection. Within 18 months siderite dissolution and calcite dissolution were observed in all four of these wells. In the remaining four wells, CO2 dissolution was observed, indicated by a slow decreased in pH from 7.5 to 7.2 with no significant change in total alkalinity or calcium concentration in the water. Inter-well communications were observed between wells 08–11 and 12–12 by means of residual “kill fluid” migration occurring from well 12–12 to well 08–11

Interactions of CO2 with Formation Waters, Oil and Minerals and CO2 storage at the Weyburn IEA EOR site, Saskatchewan, Canada

The Weyburn oil field in Saskatchewan, Canada, is hosted in Mississippian carbonates and has been subject to injection of CO2 since 2000. A detailed mineralogy study was completed as the basis for modeling of mineral storage of injected CO2. Combining the mineralogy with kinetic reaction path models and water chemistry allows estimates of mineral storage of CO2 over 50 years of injection. These results, combined with estimates of pore volume, solubility of CO2 in oil and saline formation waters, and the initial and final pore volume saturation with respect to oil, saline water and gas/supercritical fluid allow an estimate of CO2 stored in saline water, oil and minerals over 50 years of CO2 injection. Most injected CO2 is stored in oil (6.5•106 to 1.3•107 tonnes), followed closely by storage in supercritical CO2 (7.2•106 tonnes) with saline formation water (1.5 - 2•106 tonnes) and mineral storage (2 - 6•105 tonnes) being the smallest sinks. If the mineral dawsonite forms, as modeling suggests, the majority of CO2 dissolved in oil and salineformation water will be redistributed into minerals over a period of approximately 5000 years. The composition of produced fluids from a baseline sampling program, when compared to produced fluids taken three years after injection commenced, suggest that dawsonite is increasingly stable as pH decreases due to CO2 injection. The results suggest that hydrocarbon reservoirs that contain low gravity oil and little or no initial gas saturation prior to CO2 injection, may store the majority of injected CO2 solubilized in oil, making such reservoirs the preferred targets for combined enhanced oil recovery-CO2 storage projects

Quantifying CO2 pore-space saturation at the Pembina Cardium CO2 monitoring pilot (Alberta, Canada) using oxygen isotopes of reservoir fluids and gases

Geochemical and isotopic monitoring allows determination of CO2 presence in the subsurface through the sampling of produced fluids and gases at production and/or monitoring wells. This is demonstrated by data from 22 months of monitoring at the Pembina Cardium CO2 Monitoring Pilot in central Alberta, Canada. Eight wells centered around two CO2 injectors were sampled monthly between February 2005 and February 2007. Stable isotope analyses of the samples revealed that changes in the δ13CCO2 values in produced gas as well as changes in the δ18O values of the produced fluids indicate CO2 presence and identify trapping mechanisms at select production wells. Using equilibrium isotope exchange relationships and CO2 solubility calculations, fluid and gas saturations in the pore space in excess of that occupied by oil were calculated. We demonstrate that stable isotope measurements on produced fluids and gases at the Pembina Cardium CO2 storage site can be used to determine both qualitatively and quantitatively the presence of CO2 around the observation well, given that the injected CO2 is isotopically distinct

The use of stable isotope measurements for monitoring and verification of CO2 storage

Stable isotope data can assist in successful monitoring of the fate of injected CO2 in enhanced oil recovery and geological storage projects. This is demonstrated for the International Energy Agency Greenhouse Gas Weyburn-Midale CO2 Monitoring and Storage Project (Saskatchewan) and the Pembina Cardium CO2 Monitoring Project (Alberta) where fluid and gas samples from multiple wells were collected and analyzed for geochemical and isotopic compositions. In both projects, C and O isotope values of injected CO2 were sufficiently distinct from those of background CO2 in the reservoir. Consequently C and O isotope ratios constitute a suitable ‘fingerprint’ for tracing the fate of injected CO2 in the respective reservoirs

Security of Storage in Carbon Dioxide Enhanced Oil Recovery

The Pembina Cardium CO2 Monitoring Pilot was used as a test site to determine the relative roles of trapping mechanisms. Two methods to assess this distribution are presented. A geochemical approach using empirical data from the site was used to determine the phase distribution of CO2 at a number of production wells that were sampled monthly during a two-year CO2 injection pilot. In addition, a simplified reservoir simulation was performed. Results indicate that significant amounts of CO2 are stored in the oil phase thus reducing the amount of CO2 available as a buoyant free phase and hence increasing storage security

Carbon dioxide-water-silicate mineral reactions enhance CO2 storage : evidence from produced fluid measurements and geochemical modeling at the IEA Weyburn-Midale project

At the International Energy Agency Greenhouse Gas (IEA GHG) Weyburn-Midale Project in Saskatchewan, Canada, CO2 storage research takes place alongside CO2 enhanced oil recovery (EOR) in the Weyburn oil field. Over four years of production well monitoring at Weyburn, measured changes in chemical and isotopic data for produced aqueous fluids and gases (i.e. an increase in Ca2+, Mg2+, K+, SO42-, HCO3-, and CO2 concentration and a decrease in δ13CHCO3- and δ13CCO2 values), confirm the integrity of CO2 storage, trace CO2 migration and dissolution in the reservoir fluids, and record a range of water-rock- CO2 reactions including carbonate mineral dissolution and alteration of K-feldspar. K-feldspar alteration buffers the pH decrease resulting from CO2 injection, enhances aqueous CO2 storage as HCO3- (ionic trapping) and can lead to mineral storage of CO2 as CaCO3. Geochemical reaction path simulations of the water-mineral- CO2 system reproduce the changes in measured data observed over the first few years, confirming proposed reaction pathways and rates. Extension of these history matched reaction path simulations over 100s of years shows that alteration of K-feldspar and other silicate minerals present in the Weyburn reservoir will lead to further storage of injected CO2 in the aqueous phase and as carbonate minerals

Organic Solvent Contamination in Groundwater Around Natural Gas Plants

Alberta is a province that has vast deposits of natural gas. However, in its natural form it is considered sour in that it has impurities, i.e., it contains hydrogen sulphide (H2S), carbonyl sulfide (COS), carbon dioxide (CO2), mercaptans and organic sulphides. To enable the marketing of the natural gas these impurities must be removed using organic compounds and solvents. As a result of spills, leakage during processes, seepage from unlined storage ponds some of these solvents have contaminated groundwater around natural gas processing facilities.Remediation of the organic solvents is a difficult problem. To achieve an understanding of the processes involved in their degradation, a hydrogeochemical assessment of a site can be done using existing data from the site to track the development of groundwater redox zones across the different hydrostratigraphic units (HSU). This is relevant because the oxidation is hypothesized to have contributed to the biodegradation of the compounds. The objective of this global assessment is to assign a groundwater redox zone for each sample, with special emphasis placed on defining the oxidative groundwater zone (OGZ) due to its relevance to biodegradation. Ideally, the oxic groundwater zone would be defined based on the concentration of molecular oxygen (i.e., dissolved ) in groundwater (McMahon and Chapelle 2008). However, molecular oxygen, normally measured as ‘dissolved oxygen’, was not routinely measured as a field parameter in this study and therefore was unavailable to define the OGZ.The scheme adopted considers the concentrations of terminal electron acceptors (TEA) present in groundwater and measured in commonly measured parameters including oxygen, nitrate, and sulphate and dissolved metals (manganese and iron). These TEA's are consumed under progressively more reducing conditions after oxygen reduction is complete in the order: nitrate reduction, manganese reduction, iron reduction, sulphate reduction, and finally carbonate reduction (one form of methanogenesis). The results show that redox zonation is heterogeneously distributed across the site, both within and between HSUs. Multiple lines of hydrogeochemical evidence support buffered aerobic biodegradation at the site

The Electrochemical behaviour of lead in alkaline solution

Bibliography: p. 102-104

2-D Numerical Modeling of CO2 Storage in the Devonian H2S Containing Nisku Aquifer in the Wabamun Lake Area (Alberta, Canada)

AbstractThe Devonian Nisku aquifer has been identified as a suitable CO2 storage site in the Alberta Basin, but this aquifer contains significant amounts of H2S. Numerical simulations were performed to investigate the impact of dissolved H2S in the brine on the behavior of the injected CO2. No major differences in geochemical reactions were observed between model runs with and without H2S. Extensive dolomite dissolution was observed in both model runs, which caused a minor increase in porosity and permeability of the aquifer. The majority of the injected CO2 was trapped in the Middle Nisku as a free supercritical phase and the rest was dissolved in the brine