Experimental study on a single cement-fracture using CO\u3csub\u3e2\u3c/sub\u3e rich brine

The efficiency of Carbon Capture and Storage (CCS) projects is directly related to the long term sealing efficiency of barrier systems and of wellbore cement in wellbores penetrating storage reservoirs. The microfractures inside the wellbore cement provide possible pathways for CO leakage to the surface and/or fresh water aquifers, impairing the long-term containment of CO in the subsurface. The purpose of this experimental study is to understand the dynamic alteration process in the cement caused by the acidic brine. The first experiment, at ambient temperature and pressure, was conducted by flowing CO -rich brine through 1 in. by 2 in. (25.4 mm by 50.8 mm) cement cores for 4 and 8 weeks durations. The second experiment was a 4 weeks long flow-through experiment conducted at ambient conditions using a 1 in by 12 in.(25.4 mm by 304.8 mm) cement core and CO -rich brine with a core flooding system under 600 psi (4.13 MPa) confining stress. Post-experiment material analysis from both experiments confirmed leaching of Ca from reacted cement, as reported in literature. However for the first time, porosity of the reacted regions was semi-quantified applying micro-CT images. © 2010 Elsevier Ltd. © 2011 Published by Elsevier Ltd. 2 2 2 2 2

Using pressure and volumetric approaches to estimate CO2 storage capacity in deep saline aquifers

Various approaches are used to evaluate the capacity of saline aquifers to store CO2, resulting in a wide range of capacity estimates for a given aquifer. The two approaches most used are the volumetric “open aquifer” and “closed aquifer” approaches. We present four full-scale aquifer cases, where CO2 storage capacity is evaluated both volumetrically (with “open” and/or “closed” approaches) and through flow modeling. These examples show that the “open aquifer” CO2 storage capacity estimation can strongly exceed the cumulative CO2 injection from the flow model, whereas the “closed aquifer” estimates are a closer approximation to the flow-model derived capacity. An analogy to oil recovery mechanisms is presented, where the primary oil recovery mechanism is compared to CO2 aquifer storage without producing formation water; and the secondary oil recovery mechanism (water flooding) is compared to CO2 aquifer storage performed simultaneously with extraction of water for pressure maintenance. This analogy supports the finding that the “closed aquifer” approach produces a better estimate of CO2 storage without water extraction, and highlights the need for any CO2 storage estimate to specify whether it is intended to represent CO2 storage capacity with or without water extraction

Measurements of Non-Wetting Phase Trapping Applied to Carbon Dioxide Storage

We measure the trapped non-wetting phase saturation as a function of the initial saturation in sand packs. The application of the work is for carbon dioxide (CO2) storage in aquifers where capillary trapping is a rapid and effective mechanism to render injected CO2 immobile. We used analogue fluids at ambient conditions. The trapped saturation initially rises linearly with initial saturation to a value of 0.11 for oil/water systems and 0.14 for gas/water systems. There then follows a region where the residual saturation is constant with further increases in initial saturation

Regional-scale porosity and permeability variations, Peace River arch area, Alberta, Canada

This study examines the large-scale variability of porosity and permeability of the sedimentary rocks in the Phanerozoic succession in the Alberta part of the Peace River arch-area of the Western Canada sedimentary basin. The study is based on about 450,000 core analyses at approximately 22,000 wells in an area of more than 165,000 km2. Plug-scale porosity and permeability values are scaled up to the well scale by hydrostratigraphic unit, resulting in two sets of about 16,000 values each for porosity and permeability, unevenly distributed both areally and with depth. The permeability frequency distributions are lognormal for most of the units or parts of the units. The regional-scale variability of porosity and permeability is quite high, between 1 and 38% for porosity, and 0.001 md and 3 d for permeability. The clastic units of the foreland basin exhibit a relatively high correlation between permeability and porosity. Several areal trends and patterns are identified for groups of hydrostratigraphic units, patterns that change gradually from one group to another. It is hypothesized that the observed variability is caused by the dominance of the Peace River arch, carbonate deposition, or compaction at various times throughout the evolution of the basin. Based on the predominant controlling factor, the geological history can be divided into four periods: arch influence during the Early to Middle Devonian, reefal carbonate-deposition influence during the Middle to Late Devonian, passive margin influence during the Late Devonian to Middle Jurassic, and orogenic influence since the Middle Jurassic

Assessing the Effect of Timing of Availability for Carbon Dioxide Storage in the Largest Oil and Gas Pools in the Alberta Basin: Description of Data and Methodology

Carbon dioxide capture from large stationary sources and storage in geological media is a technologically-feasible mitigation measure for the reduction of anthropogenic emissions of CO2 to the atmosphere in response to climate change. Carbon dioxide (CO2) can be sequestered underground in oil and gas reservoirs, in deep saline aquifers, in uneconomic coal beds and in salt caverns. The Alberta Basin provides a very large capacity for CO2 storage in oil and gas reservoirs, along with significant capacity in deep saline formations and possible unmineable coal beds. Regional assessments of potential geological CO2 storage capacity have largely focused so far on estimating the total capacity that might be available within each type of reservoir. While deep saline formations are effectively able to accept CO2 immediately, the storage potential of other classes of candidate storage reservoirs, primarily oil and gas fields, is not fully available at present time. Capacity estimates to date have largely overlooked rates of depletion in these types of storage reservoirs and typically report the total estimated storage capacity that will be available upon depletion. However, CO2 storage will not (and cannot economically) begin until the recoverable oil and gas have been produced via traditional means. This report describes a reevaluation of the CO2 storage capacity and an assessment of the timing of availability of the oil and gas pools in the Alberta Basin with very large storage capacity (>5 MtCO2 each) that are being looked at as likely targets for early implementation of CO2 storage in the region. Over 36,000 non-commingled (i.e., single) oil and gas pools were examined with effective CO2 storage capacities being individually estimated. For each pool, the life expectancy was estimated based on a combination of production decline analysis constrained by the remaining recoverable reserves and an assessment of economic viability, yielding an estimated depletion date, or year that it will be available for CO2 storage. The modeling framework and assumptions used to assess the impact of the timing of CO2 storage resource availability on the region’s deployment of CCS technologies is also described. The purpose of this report is to describe the data and methodology for examining the carbon dioxide (CO2) storage capacity resource of a major hydrocarbon province incorporating estimated depletion dates for its oil and gas fields with the largest CO2 storage capacity. This allows the development of a projected timeline for CO2 storage availability across the basin and enables a more realistic examination of potential oil and gas field CO2 storage utilization by the region’s large CO2 point sources. The Alberta Basin of western Canada was selected for this initial examination as a representative mature basin, and the development of capacity and depletion date estimates for the 227 largest oil and gas pools (with a total storage capacity of 4.7 GtCO2) is described, along with the impact on source-reservoir pairing and resulting CO2 transport and storage economics. The analysis indicates that timing of storage resource availability has a significant impact on the mix of storage reservoirs selected for utilization at a given time, and further confirms the value that all available reservoir types offer, providing important insights regarding CO2 storage implementation to this and other major oil and gas basins throughout North America and the rest of the world. For CCS technologies to deploy successfully and offer a meaningful contribution to climate change mitigation, CO2 storage reservoirs must be available not only where needed (preferably co-located with or near large concentrations of CO2 sources or emissions centers) but also when needed. The timing of CO2 storage resource availability is therefore an important factor to consider when assessing the real opportunities for CCS deployment in a given region