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At the Cooperative Research Centre for Greenhouse Gas Technology's (CO2CRC) field site in the Otway Basin of Victoria, Australia, investigations into the storage of CO 2 -rich gas in a depleted hydrocarbon gas field have been conducted in the Waarre C reservoir. The injected gas from the nearby Buttress field contained 75 mol% CO 2 , 21 mol% CH 4 with the remaining balance being a mixture of wet hydrocarbons, condensate and nitrogen. Chemical tracers (sulphur hexafluoride, SF 6 ; krypton, Kr; perdeuterated methane, CD 4 ) were added on the basis of literature surveys and small volume trials at the Frio II Brine experiment in Texas. The aim of the project was to measure, monitor and verify the presence of injected CO 2 in a depleted gas field and that the arrival of tracers was a major component of demonstrating breakthrough of CO 2 at the monitoring well, Naylor-1. The paper focuses on methods developed for the injection, recovery and analysis of samples collected at the Naylor-1 well. Results of tracer analysis compare well with other data collected (including pH and density measurements) to demonstrate breakthrough. A slip-stream injection system was designed to deliver the tracers mixed with the CO 2 -rich gas into the subsurface at the CRC-1 well. The tracers were added to the gas stream 17 days after the start of injection (CO 2 injection commenced 18th March, 2008) into the depleted natural gas field at Naylor. A U-tube system was used to retrieve the samples from the Naylor-1 monitoring well. Collected gas and formation water samples were analysed in detail for gas composition, tracers, isotopes ( 13 C CO 2 mainly) and inorganic geochemistry for the broader project. The tracer results confirm that CO 2 breakthrough at the monitoring well occurred within the predicted times. However the interval between samples taken from the U-tubes was too coarse to resolve detailed differences in arrival times between the CO 2 and tracers. Of the three tracers used, SF 6 provided the clearest evidence of breakthrough at U-tube 2. Kr, because of its abundance in air, and its potential to be present in the subsurface, was more prone to contamination and had higher background levels prior to breakthrough. CD 4 was expected to provide some more unique data based on the presence of abundant CH 4 in the reservoir interval. With hindsight, larger volumes should have been injected to facilitate comparisons with the other tracers and add value to the data set. The test of CD 4 however acted as a suitable proof of concept that CD 4 could be used in such a high background of CH 4 . Further work is ongoing to generate data for partition coefficients between supercritical CO 2 , CH 4 and water under the injection conditions. [ABSTRACT FROM AUTHOR]

As part of the CO2CRC Otway Residual Saturation and Dissolution Test, a series of field tests were conducted at their project site in Victoria, Australia, with the primary goal of developing and assessing methods for quantifying residual CO 2 saturation in a saline aquifer. This paper reports the outcome of one of these tests, a single-well “push–pull” tracer test that uses novel reactive esters (i.e., propylene glycol diacetate, triacetin and tripropionin). For this tracer test, the ester is injected (pushed) into the reservoir where residual saturation has been established using CO 2 , and maintained by pushing with CO 2 saturated water (to prevent changes in saturation due to CO 2 dissolution). The ester is partially hydrolysed by the formation water to yield multiple compounds (i.e., the corresponding alcohol and acid generated from the ester). During water production (pull) from the same well, these compounds will partition differentially between the residual supercritical carbon dioxide phase and water phase, leading to chromatographic separation. By modelling the concentration profiles of these tracers in production water samples and using the experimentally determined partition coefficients, we generate two consistent residual saturation estimates using two separate modelling techniques, one a simple finite difference simulation of the tracer velocity field and the other a standard multiphase simulation code. [ABSTRACT FROM AUTHOR]

Abstract: Chemical tracers have been used in various C capture and storage (CCS) projects worldwide primarily to provide information regarding subsurface migration of CO2 and to verify CO2 containment. Understanding the movement and interactions of CO2 in the subsurface is a challenging task considering the variety of states in which it exists (i.e. gas, liquid, supercritical, dissolved in water) and the range of possible storage mechanisms (i.e. residual or capillary trapping, dissolved in water, structural trapping or incorporation into minerals). This paper critically reviews several chemical tracer applications and case studies for CCS projects. In many instances, there are parallels (e.g. tracer classes and applications) between tracers in the oil and gas industry and in CCS. It has been shown that chemical tracers can complement geophysical measurements (e.g. seismic) in understanding the formation behaviour of CO2. Although tracers have been successfully used in many CCS projects, some fundamental information, for example partitioning and adsorption, about the behaviour of tracers is still lacking and this can be an issue when interpreting tracer data (e.g. determining leakage rates). In this paper the deployment and recovery of chemical tracers and their use on various CCS projects are described. [Copyright &y& Elsevier]

Abstract: The mechanisms for storage of CO2 in rock formations include structural/stratigraphic, mineral, solubility and residual trapping. Residual trapping is very important in terms of both containment security and storage capacity. However, to date, the contribution from residual trapping (i.e. immobilisation of supercritical fluid via capillarity in pore spaces) is still relatively difficult to quantify accurately. Using a laboratory-based testing program, this study demonstrates the feasibility of using reactive ester tracers (i.e. triacetin, propylene glycol diacetate and tripropionin), which partition between a mobile water phase and a stationary supercritical CO2 phase, to quantify the residual CO2 saturation, Sgr , of a rock formation. The proposed single-well test involves injecting these tracers into the subsurface, followed by CO2 saturated water, where the ester tracers slowly hydrolyse to form products with differing partition coefficients. After a suitable period of time, allowing for partial hydrolysis, water containing the tracer mixture is produced from the subsurface and analysed using gas chromatography mass spectrometry (GCMS). A numerical simulator of the tracer behaviour in a reservoir is used to explain the differential breakthrough of these tracer compounds during water production to estimate Sgr . Computer modelling suggests that the use of esters tracers to determine CO2 residual saturation is a potentially robust method. The supercritical CO2/water partition coefficients directly dictate the amount of time that each tracer spends in the CO2 and water phases. As such for modelling of tracer behaviour and estimating Sgr , knowing the tracer partition coefficient is essential; in this paper, the first laboratory study to determine the partition coefficients of these reactive ester tracers is described. [Copyright &y& Elsevier]

Abstract: In 1983, Schoell et al. [Schoell, M., Faber, E., Coleman, M.L., 1983. Carbon and hydrogen isotopic compositions of the NBS 22 and NBS 21 stable isotope reference materials: an inter-laboratory comparison. Organic Geochemistry 5, 3–6] carried out an inter-laboratory comparison of the International Atomic Energy Agency (IAEA) reference materials NBS 21 (a graphite) and NBS 22 (an oil). At that time they found that NBS 22 in particular to be more depleted in 13C than the values published by the IAEA at that time (i.e., δ 13C of −29.81‰ PDB ±0.06 as opposed to δ 13C of −29.4‰ PDB). Even so, to this day, the IAEA has subsequently used a value of δ 13C of −29.7‰±0.2 VPDB. Following the advent of the new IAEA VPDB scale, defined by NBS 19 (a carbonate), this laboratory at the Commonwealth Scientific and Industrial Research Organisation (CSIRO) Petroleum and Exploration and Mining Divisions in North Ryde, NSW, Australia found that a number of the reference materials depleted in 13C (especially “organic” type reference materials) to be more depleted in 13C on the VPDB scale than expected. In particular, NBS 22 appears to be 0.25‰ more depleted in 13C than generally accepted values compared with a suite of carbonate standards run together. We suggest that the NBS 22 and other “organic” reference materials have probably all been calibrated to NBS 21 or 22 and should now be redefined on the VPDB scale. [Copyright &y& Elsevier]

Legislation and guidelines developed for Carbon Capture and Storage (CCS) have set performance requirements to minimize leakage risk, and to quantify and remediate any leaks that arise. For compliance it is necessary to have a comprehensive understanding of the possible spread, fate and impacts of any leaked CO 2 , and the ability to detect and quantify any CO 2 seepage into marine or terrestrial environments. Over the past decade, a number of field scale CO 2 release experiments have been conducted around the world to address many of the uncertainties regarding the characteristics of near-surface expression of CO 2 in terms of the impact and quantitation of CO 2 leaks. In these experiments, either free phase or dissolved CO 2 was injected and released into the shallow subsurface so as to artificially simulate a CO 2 leak into the near-surface environment. The experiments differ in a number of ways, from the geological conditions, surface environments, injection rates and experimental set-up - including the injection and monitoring strategy. These experiments have provided abundant information to aid in the development of our scientific understanding of environmental impacts of CO 2 while assessing state of the art monitoring techniques. We collated a global dataset of field-scale shallow (depths < ~25 m) controlled CO 2 release experiments. The dataset includes 14 different field experiment locations, of which nine intended to release CO 2 to the surface, and the remaining sites intended for CO 2 to remain in the shallow subsurface. Several release experiments have been conducted at half of these sites, and so in total, 41 different CO 2 release tests have taken place at the 14 sites in our dataset. We scrutinized our dataset to establish: (i) the range of experimental approaches and settings explored to date (such as the environment, subsurface conditions, injection strategy and whether gaseous or dissolved CO 2 were injected and in what quantities); (ii) the range of CO 2 injection and surface release rates at these experiments; (iii) the collective learnings about the surface and subsurface manifestation of the CO 2 release, the spread and fate of the CO 2 , rates of CO 2 flux to surface, and methods of measuring these; (iv) the strengths and limitations of current approaches for detecting and quantifying CO 2. This allowed us to highlight where uncertainties remain and identify knowledge gaps that future experiments should seek to address. Further, drawing on the collective experiences, we have identified common issues or complications which future CO 2 release experiments can learn from. [ABSTRACT FROM AUTHOR]

An understanding of the fundamental properties of chemical tracers (e.g. partitioning and sorption) is critical for assessing their subsurface behavior and to accurately model and interpret field tracer data. Carbon dioxide–water (CO 2 /H 2 O) partition coefficients have been previously determined for the reactive ester tracers, propylene glycol diacetate, triacetin and tripropionin, suggesting their suitability for assessing the residual trapping capacity of a geological formation for CO 2 in a single well chemical tracer test. Understanding the temperature dependent behavior of chemical tracers significantly enhances their utility in field trials leading to a more accurate estimate of reservoir properties. However, very little information is known on the relationship between temperature and the partitioning process for these chemical tracers. In this paper, the temperature dependence of the partitioning process has been determined for temperatures ranging from 60 to 120 °C. The variations in the partition coefficient with temperature were shown to correlate reasonably well with the van't Hoff equation for all tracers. The enthalpy associated with the partitioning process was determined by a regression fit to this equation and was shown to be the smallest for propylene glycol diacetate and the largest for tripropionin. It was found that the estimated enthalpy is approximately linearly correlated with the number of carbon atoms in the organic ester. Furthermore, we have shown that the temperature dependence of the tracer partition coefficient causes significant variation in the estimate of residual saturation. [ABSTRACT FROM AUTHOR]

Abstract Chemical tracers can be an effective means of detecting, attributing and quantifying any leaks to the surface from geological CO 2 stores. CO 2 release experiments have found it difficult to ascertain the fate, or quantify the volume of CO 2 without the application of tracers. However, a significant proportion of global CO 2 storage capacity is located offshore, and the marine environment poses constraints that could limit the success of using tracers. These constraints include uncertainties in the behaviour of tracers in marine sediments and the water column and sampling challenges. However, to date there have been few experimental investigations to address these uncertainties. Here, we used a benchtop experimental setup to explore how effectively methane, a common constituent of captured CO 2 and of reservoir fluids, can aid the quantitation of CO 2 leakage in aqueous environments. The experiment simulated gas leakage into sediments that mimic the seabed, and we measured the partitioning of co-released gases under different environmental conditions and injection rates. We find that the style of seepage and the fate of the CO 2 are affected by the presence of a sand layer and the injection rate. We discuss the implications for leak monitoring approaches, including how tracers may be used to quantify the leak rates and fate of CO 2 in aqueous environments. Our work contributes to ongoing efforts to develop robust offshore monitoring system that will assure operators, regulatory bodies and the public of CO 2 storage integrity. Highlights • A large proportion of global CO 2 storage capacity is located offshore. • Quantifying CO 2 leaks into aquatic environments is challenging. • Our experiments test methane as a chemical tracer for CO 2 leakage to sea or lake bed. • We find that bubble stream gas content can inform CO 2 leak rate and fate. • The proportion of CO 2 dissolution is affected by leak style. [ABSTRACT FROM AUTHOR]

Graphical abstract Highlights • Carbonate aquifers (calcite surfaces). • Dissolution of organic acid components in crude oil (stearic acid). • CO 2 trapping in deep saline aquifers and depleted hydrocarbon reservoirs and their associated risks in the presence of organic acid components. Abstract Hypothesis CO 2 geological storage (CGS) involves different mechanisms which can store millions of tonnes of CO 2 per year in depleted hydrocarbon reservoirs and deep saline aquifers. But their storage capacity is influenced by the presence of different carboxylic compounds in the reservoir. These molecules strongly affect the water wetness of the rock, which has a dramatic impact on storage capacities and containment security. However, precise understanding of how these carboxylic acids influence the rock's CO 2 -wettability is lacking. Experiments We thus systematically analysed these relationships as a function of pressure, temperature, storage depth and organic acid concentrations. A particular focus was on identifying organic acid concentration thresholds above which storage efficiency may get influenced significantly. Findings These thresholds (defined for structural trapping as a water contact angle θ > 90°; and for capillary trapping when primary drainage is unaffected, i.e. θ > 50°) were very low for structural trapping (∼10−3–10−7 M organic acid concentration C organic) and extremely low for capillary trapping (10−7 M to below 10−10 M C organic). Since minute organic acid concentrations are always present in deep saline aquifers and certainly in depleted hydrocarbon reservoirs, significantly lower storage capacities and containment security than previously thought can be predicted in carbonate reservoirs, and reservoir-scale models and evaluation schemes need to account for these effects to de-risk CGS projects. [ABSTRACT FROM AUTHOR]

Partition (or distribution) coefficients determine the relative equilibrium concentrations of chemical constituents (or chemical tracers) in each of the phases of a multi-phase system under dilute conditions. The various fluid phases in a reservoir have differing transport properties (e.g. varying relative permeability) and to correctly interpret the behaviour of injected chemical tracers it is essential that accurate partition coefficients are known. In the context of carbon geosequestration or long-term storage of CO 2 , chemical tracers will be predominantly exposed to an environment consisting of supercritical CO 2 and formation water as the main fluid phases. To estimate/simulate the reservoir properties relevant to injected CO 2 tagged with chemical tracers, it is therefore necessary to incorporate high pressure/temperature CO 2 /water partition coefficients into any model/simulation. In this paper, we present a method to determine these partition coefficients for gaseous chemical tracers using a variation of the widely used EPICS (or equilibrium partitioning in a closed system) method. With this method, only the concentration in one phase (in this case, CO 2 ) needs to be measured. We then report these values for a series of representative chemical tracers (i.e. krypton, xenon, sulfur hexafluoride, perdeuterated methane and R134a) at pressure/temperature conditions that have been previously used at the CO2CRC's Otway CCS demonstration project in Victoria, Australia. These values were generally lower than the corresponding Henry's Law coefficients at comparable temperatures. Experiments also examined the impact of adding CH 4 to the system to mimic feedstock gas at the CO2CRC Otway project and provide data pertinent to scenarios where CO 2 is injected into depleted CH 4 gas fields. These values are compared with Henry's Law coefficients and another recently published set of high pressure/temperature partition coefficients. With computational simulations, we have shown that these differences are potentially significant and demonstrate their impact in three typical CO 2 geo-sequestration scenarios (i.e. injection into two types of aquifers and injection into a depleted reservoir with a gas cap). [ABSTRACT FROM AUTHOR]

Perfluorocarbon (PFC) compounds have been used as chemical tracer molecules to understand the movement of supercritical carbon dioxide for geosequestration monitoring and verification purposes. A commonly used method for detecting PFCs involves the collection of a sample from either soil-gas or the atmosphere via carbon-based sorbents which are then analyzed in a laboratory. However, PFC analysis in aquatic environments is neglected and this is an issue that needs to be considered since the PFC is likely to undergo permeation through the overlying water formations. This paper presents for the first time an innovative analytical method for the trace level in situ detection of PFCs in water. It reports on the development of a sensor based on mid-infrared attenuated total reflection (MIR-ATR) spectroscopy for determining the concentration of perfluoromethylcyclohexane (PMCH) and perfluoro-1,3-dimethylcyclohexane (PDCH) in aquatic systems. The sensor comprises a zinc selenide waveguide with the surface modified by a thin polymer film. The sensitivity of this device was investigated as a function of polymer type, coating thickness, and solution flow rates. The limit of detection (LOD) was determined to be 23 ppb and 79 ppb for PMCH and PDCH, respectively when using a 5 μm thick polyisobutylene (PIB) coated waveguide. This study has shown that the MIR-ATR sensor can be used to directly quantify PFC-based chemical tracer compounds in water over the 20-400 ppb concentration range. [ABSTRACT FROM AUTHOR]

Abstract: Organic geochemical and petrological assessment of coals/coaly shales and fine grained sediments, coupled with organic geochemical analyses of oil samples, all from Permo–Triassic sections of the Southern Sydney Basin (Australia), have enabled identification of the source for the widely distributed oil shows and oil seeps in this region. The Permian coals have higher hydrogen indices, higher liptinite contents, and much higher total organic matter extract yields than the fine grained sediments. A variety of source specific parameters obtained from n-alkanes, regular isoprenoids, terpanes, steranes and diasteranes indicate that the oil shows and seeps were generated and expelled predominantly from higher plant derived organic matter deposited in oxic environments. The source and maturity related biomarkers and aromatic hydrocarbon distributions of the oils are similar to those of the coals. The oil-coal relationship also is demonstrated by similarities in the carbon isotopic composition of the total oils, coal extracts, and their individual n-alkanes. Extracts from the Permo–Triassic fine grained sediments, on the other hand, have organic geochemical signatures indicative of mixed terrestrial and prokaryotic organic matter deposited in suboxic environments, which are significantly different from both the oils and coal extracts. The molecular signatures indicating the presence of prokaryotic organic matter in some of the coal extracts and oils may be due to thin sections of possibly calcareous lithologies interbedded within the coal measures. The genetic relationship between the oils and coals provides new evidence for the generation and expulsion of oils from the Permian coals and raises the possibility for commercial oil accumulations in the Permian and Early Triassic sandstones, potentially in the deeper offshore part of the Sydney Basin. [Copyright &y& Elsevier]

In February 2019, at the CSIRO In-Situ Laboratory CCS project, a test was conducted where 38 t of gaseous CO 2 were injected over 5 days into a fault zone at a depth of approximately 340 m. As a release test, this project enabled the testing and validation of surface and shallow well monitoring strategies at intermediate depths (i.e. depths much deeper than previous release projects and shallower than reservoirs used for CO 2 storage). One of the aims of this project is to understand how CO 2 would behave at intermediate depths if it did migrate from deeper depths (i.e. from a storage reservoir); the CO 2 was not intended to migrate to the shallow subsurface or to surface/atmosphere. To verify that the injected CO 2 remained in the subsurface, and to comply with environmental performance requirements on site, a comprehensive surface gas and groundwater monitoring program was conducted. The monitoring strategy was designed such that any leakage(s) to the surface of injected CO 2 would be detected, mapped and, ultimately, quantified. The surface air monitoring program was comprised of three different but complementary approaches allowing data to be efficiently collected over different spatial and temporal scales. These approaches included continuous soil-gas chamber measurements at fixed locations, periodic soil-gas chamber measurements on gridded locations and near-surface atmospheric measurements on a mobile platform. The surface air monitoring approaches gave self-consistent results and reduced the risk of "false negative" test results. The only anomalous CO 2 detected at the surface flowed from the observation well and could be directly attributed to a breach in the well casing at the injection depth providing a conduit for CO 2 /water to rise to the surface. Groundwater monitoring program revealed no impact on the groundwater resources attributable to the carbon injection project. Based on this work, we demonstrate that this multi-pronged monitoring strategy can be utilized to minimize the overall resources devoted to monitoring by increasing the number of monitoring approaches and diminishing the resources devoted to each technique. By maximizing the effectiveness of each element of the monitoring program, a cost-efficient and robust monitoring strategy capable of early leak detection and attribution of any leaking CO 2 can be achieved. [ABSTRACT FROM AUTHOR]

The article offers information on the Otway Project, located in Victoria in Australia. It mentions how the said project provides demonstrations on large-scale carbon capture and storage (CCS) in depleted gas field. Moreover, it features how public consent and risk assessment affects the demonstration of carbon storages.