CO2 Storage In Formations Research Articles

Minimum Carbon Credit Cost Estimation for Carbon Geological Storage in the Mae Moh Basin, Thailand

Carbon geological storage (CGS) is one of the key processes in carbon capture and storage (CCS) technologies, which are used to reduce CO2 emissions and achieve carbon-neutrality and net-zero emissions in developing countries. In Thailand, the Mae Moh basin is a potential site for implementing CGS due to the presence of a structural trap that can seal the CO2 storage formation. However, the cost of CGS projects needs to be subsidized by selling carbon credits in order to reach the project breakeven. Therefore, this paper estimates the economic components of a CGS project in the Mae Moh basin by designing the well completion and operating parameters for CO2 injection. The capital costs and operating costs of the process components were calculated, and the minimum carbon credit cost required to cover the total costs of the CGS project was determined. The results indicate that the designed system proposes an operating gas injection rate of 1.454 MMscf/day, which is equivalent to 29,530 tCO2e per year per well. Additionally, the minimum carbon credit cost was estimated to be USD 70.77 per tCO2e in order to achieve breakeven for the best case CGS project, which was found to be much higher than the current market price of carbon credit in Thailand, at around USD 3.5 per tCO2e. To enhance the economic prospects of this area, it is imperative to promote a policy of improving the cost of carbon credit for CGS projects in Thailand.

Maritime boundaries in the energy transition: carbon dioxide (CO2) storage across maritime jurisdictions

Governments around the world are looking to ensure their transition to full low-carbon economies whilst tackling climate change by implementing offshore carbon capture and storage (CCS) – a method of permanently removing carbon dioxide (CO2) from the burning of fossil fuels and burying it deep below the seabed in suitable geological formations. Among the main targets of such geological formations are depleted, or nearly depleted, offshore oil and gas reservoirs within existing oil-producing fields. However, such reservoirs will frequently transcend maritime boundaries and jurisdictions, ie a shared geological formation could be used on both sides of the maritime boundary for CO2 sequestration and storage. This raises the potential for disputes among nations, transboundary environmental degradation, and business disruption. The paper discusses the role of CCS in the low-carbon energy transition, focusing specifically on international legal aspects related to the storage of CO2 in sub-seabed geological formations of the continental shelf. Ongoing CO2 storage projects are examined to showcase critical technical aspects, including reservoir selection, well design, and post-injection monitoring. The analysis highlights the need for international coordination in situations where CO2 storage occurs across an international boundary and the importance of consent from all states with jurisdiction over the relevant CO2 storage formations. The paper concludes that existing maritime boundary agreements, including those with straddling deposit clauses, are unlikely to cover transboundary CO2 storage operations, except if they are considered incidental to ongoing petroleum operations.

Time-Lapse Pulsed-Neutron Logs for Carbon Capture and Sequestration: Practical Learnings and Key Insights

Pulsed-neutron logs are a staple of time-lapse monitoring programs for saline aquifer carbon capture and sequestration (CCS) projects and are unsurprisingly the most frequently run wireline logs in both injection and monitoring wells. While the emphasis imposed by government regulators and the focus of operators to date has been on the verification of CO2 containment, it is envisioned that a savvy interpretation of the multiple independent measurements should be able to unlock much greater value for the project than merely detecting the location of stored CO2. Recently introduced capabilities for novel measurements and improved environmental compensation should further increase the repeatability, interpretability, and value of these logs. We reviewed more than 30 time-lapse runs of pulsed-neutron logs acquired over a period of 15 years on three mature CCS projects using both previous- and new-generation pulsed-neutron tools, including measurements of formation sigma, hydrogen index, and fast neutron cross section. Special attention in processing is required when changes occur to the wellbore environment between runs, although this is mitigated by the improved environmental compensation scheme of the newer tool. We performed both standalone estimates of CO2 saturation from single-physics time-lapse measurements and simultaneous interpretation of multiple independent time-lapse measurements and studied the results side-by-side with openhole log interpretation, core analysis, and well test results from the evaluation phase. The apparent changes in saturation were framed within the context of the injection history and important events in the life of the wells. A first finding is that differences in apparent CO2 saturation between the various independent measurement physics of the pulsed-neutron tool are often reconcilable and may carry additional information about the state of the well or reservoir. With respect to verification of containment, depending on the well configuration, it may be possible to differentiate between CO2 in the formation and CO2 in the annulus. The interpreted CO2 saturation itself can have different significance depending on the timing of acquisition and the type of well. Measured at the right time, it is a direct in-situ measurement of formation CO2 storage efficiency. In other cases, the interpretation reveals formation dryout in the near-wellbore region of injection wells, a condition that may presage loss of injectivity. We now understand that it is important for operators to plan the timing and frequency of pulsed-neutron runs according to what they want to measure and not based solely on regulatory obligations. In a CCS project, time-lapse pulsed-neutron logs should be thought of as much more than simple indicators of the presence and migration of CO2. They give important information about migration pathways. They can also help to quantify essential uncertainties on reservoir performance that are difficult to ascertain during evaluation. For example, storage efficiency is difficult to quantify with openhole logs since the formation is initially at zero CO2 saturation. Yet it is one of the keys to determining the ultimate storage capacity of any reservoir. Time-lapse pulsed-neutron logs provide an abundance of information that, when properly history matched, can greatly improve our models of CCS reservoirs to better navigate both the economic and operational risks associated with these projects.

Semi-Automated Rock Classification for Permeability Estimation Using High-Resolution Computed Tomography Scan Images, Core Photos, and Well Logs

Summary Reliable estimation of petrophysical properties can be challenging, especially in geological formations with rapid variation in the spatial distribution of rock components. The spatial distribution of rock components, also known as rock fabric, is often not captured by conventional well logs that are typically used for the estimation of petrophysical properties. The aforementioned challenge is rooted in the limited vertical resolution of conventional well logging tools. Alternatively, specialized tools and techniques, such as nuclear magnetic resonance (NMR) and computed tomography (CT) scan images, can provide information on the variation in the rock fabric of geological formations. The objectives of this paper are (a) to use 2D CT scan images and core photos, conventional well logs, NMR logs, and core-measured properties for semi-automated rock classification, (b) to develop class-based rock physics models for enhanced petrophysical properties estimation, and (c) to provide a method to expedite the detection of quantitative image-based rock classes in cored wells. First, we conducted conventional formation evaluation (CFE) for the initial assessment of petrophysical properties. Then, we implemented three different rock classification techniques for class-based estimation of petrophysical properties. The first of the rock classification techniques uses routine core analysis (RCA) data to define hydraulic units. The second rock classification technique uses NMR data to characterize the changes in pore-size distribution of the evaluated formation. The last rock classification technique integrates quantitative image-based features from CT scan images and core photos with NMR data. Finally, the obtained rock classes from the abovementioned rock classification techniques are used to derive class-based permeability models. We applied the proposed workflow to a pilot well drilled in a saline water aquifer formation that will be used for CO2 injection and storage in the Northern Lights carbon capture and storage (CCS) project. The extracted image-based rock fabric features were in agreement with the visual aspect of the evaluated depth intervals. The detected rock classes captured the fluid-flow behavior using a permeability-based cost function in two of the implemented rock classification techniques, the variation in petrophysical and compositional properties through well logs, and quantitative rock fabric of the evaluated depth interval through the core image data. Finally, the use of class-based rock physics models improved permeability estimates, decreasing the mean relative error by up to 37% compared with formation-based permeability estimates from a conventional method (formation-based porosity-permeability correlations). One of the key contributions of the proposed workflow is that it integrates conventional well logs, core-measured properties, NMR logs, and high-resolution image data. As a result, the obtained integrated rock classes capture key petrophysical and geological parameters of the evaluated depth intervals that are typically not included in rock classification efforts. The obtained integrated rock classes can potentially improve the development of accurate geological models, which are used in simulation efforts as a screening tool for the selection of geological formations for CO2 storage as well as for storage capacity, selection of CO2 injection intervals, and containment forecasting.

A State-of-the-Art Review on Technology for Carbon Utilization and Storage

Carbon capture utilization and storage (CCUS) technologies are regarded as an economically feasible way to minimize greenhouse gas emissions. In this paper, various aspects of CCUS are reviewed and discussed, including the use of geological sequestration, ocean sequestration and various mineral carbon mineralization with its accelerated carbonization methods. By chemically reacting CO2 with calcium or magnesium-containing minerals, mineral carbonation technology creates stable carbonate compounds that do not require ongoing liability or monitoring. In addition, using industrial waste residues as a source of carbonate minerals appears as an option because they are less expensive and easily accessible close to CO2 emitters and have higher reactivity than natural minerals. Among those geological formations for CO2 storage, carbon microbubbles sequestration provides the economic leak-free option of carbon capture and storage. This paper first presents the advantages and disadvantages of various ways of storing carbon dioxide; then, it proposes a new method of injecting carbon dioxide and industrial waste into underground cavities.

Selecting Geological Formations for CO2 Storage: A Comparative Rating System

Underground storage of carbon dioxide (CO2) in geological formations plays a vital role in carbon capture and storage (CCS) technology. It involves capturing CO2 emissions from industrial processes and power generation and storing them underground, thereby reducing greenhouse gas emissions and curbing the impact of climate change. This review paper features a comparative analysis of CO2 storage in deep saline aquifers, depleted reservoirs, coal seams, basaltic formations and clastic formations. The comparison has been drawn based upon seven factors carefully selected from the literature, i.e., safety, storage capacity, injection rates, efficiency, residual trapping, containment and integrity and potential to improve, and all of these factors have been rated from low (1) to high (5) based upon their individual traits. Based upon these factors, an overall M.H. rating system has been developed to categorize geological formations for CO2 storage and it is observed that deep water aquifers and basaltic formations are the most effective options for CO2 storage. Lastly, a detailed way forward has been suggested, which can help researchers and policymakers to find more viable ways to enhance the efficiency of CO2 storage in various geological formations.

Wettability variation and its impact on CO2 storage capacity at the Wyoming CarbonSAFE storage hub: An experimental approach

Meeting global and national net zero carbon emission targets will require geologic carbon disposal. The U.S. Department of Energy (DOE) has accordingly funded significant research in this area, including the Wyoming CarbonSAFE project at Dry Fork Station (DFS) in Campbell County, Wyoming. This work studied wettability on micro- and macro-scales, CO2 storage potential, and the correlation between the two to support the Wyoming CarbonSAFE project’s subsurface assessment. During the study, a target formation’s wettability was found to affect how much CO2 can be stored in a given formation.In this study, representative rock samples were selected from the target storage formations— Lakota, Hulett, and Minnelusa—based on the heterogeneity of the lithology, permeability, and porosity of the respective formations. The rock samples are all fine-grained sandstone with variable cementation and bedding structure, including different scales of laminated bedding. The porosity and permeability vary within the range of 9.0–14.3% and 0.1–28.9 mD, respectively. These rock samples were prepared for the micro-scale wettability (contact angle measurement), macro-scale wettability (wettability index derived from unsteady-state flow characterization for the core plugs), and CO2 storage evaluation. The macro-scale experiments suggested that wettability appeared to dominate the CO2 storage potential performance during the drainage process, where less water-wet behavior promoted higher CO2 storage potential. The micro-scale wettability tests showed that the rock samples at the studied reservoir conditions behaved water-wet and became more water-wet as pressure increased. This kind of wettability change discourages further CO2 storage potential yet benefits the CO2 residual trapping as the CO2 injection proceeds for the studied area. The results allow the recommendation of the best reservoir candidate for storage based on wettability that affects CO2 storage. The work presented in this study provides valuable insights into wettability’s effect on the CO2 storage capacity and wettability’s importance when identifying the optimal CO2 storage formation to meet the project’s goals.

Characterization of two-phase flow in a faulted sandstone

Fault zones present in some underground CO2 storage formations can impact on injectivity, storage capacity, and the path taken by migrating CO2, including possible leakage to overlying formations and the escape of a plume beyond the area of a demarcated storage lease licence. A thorough understanding of the 2-phase flow in fault zones is therefore essential to de-risk any storage location where faults could be present. Many previous studies have addressed top-seal risks from fault reactivation, but the influence of intra-reservoir faults on flow within the target storage formations has received less attention. Studies of intraformational faults in sandstones have typically used plugs cored from outcrops or from subsurface boreholes, where important aspects of the geological history such as the stress conditions during faulting, and the degree of post-faulting compaction and cementation may be poorly constrained. Moreover, only intact fault rocks can be cored and re-loaded under stress with this approach, so that it is very difficult to establish the interacting effects or rock fractures and cataclastic gouge in a single experiment using borehole/outcrop samples.This study investigates newly created fault rock in sandstone that has been deformed under controlled conditions and without the effects of secondary cementation. We used a large direct shear rig to deform a large, water-saturated Bentheimer sandstone block to sufficient displacement (40mm) and under enough overburden pressure (25 MPa) to create a zone of cataclastic gouge several mm thick bounded by a damage zone of fractured rock. The sheared block was cored at an inclined angle while deep frozen to extract an oriented plug containing a complete and intact section of fault rock that could be reloaded under hydrostatic conditions in an x-ray transparent core holder. The faulted plug of Bentheimer was used for running steady-state drainage and imbibition 2-phase flow experiments. The fluid saturation and its spatial distribution in 3D inside the faulted plug were dynamically monitored during all stages of the experiment in a medical x-ray CT scanner.Analysis of the flow patterns revealed from the X-ray CT images collected over time enables us to characterize in detail, the influence of recently formed fault core and damage zones on fluid flow both during drainage as gas breaks across the fault zone, and as water re-invades during imbibition. The fault core acts as a semi-permeable membrane that is only permeable to the wetting phase (water) under pressure differentials less than the capillary entry pressure (Pce) of the membrane. During drainage stages, the high Pce of the fault core led to backfilling of the upstream end of the core and almost to compartmentalization of the sample. The fracture network that exists in the damage zone played a critical role in keeping the upstream side of the fault core connected to the downstream side. During imbibition stages, the high Pce of the fault core led to significant gas trapping at the upstream side of the fault core adjacent to the fault core-damage zone interface. While the fault core formed a barrier to flow, the fracture network can provide bypass pathways for gas flow. In this particular sample bypassing through fractures was sufficient such that for a particular value of average gas saturation the flow rate was faster in the faulted rock than in the unfaulted reservoir rock.

Study Explores Potential of Carbon Leakage in Denver-Julesburg Basin Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210256, “Wellbore-Integrity Impact on Carbon Leakage To Ensure Safe Geological Sequestration,” by Yanrui Ning, SPE, and Ali Tura, Colorado School of Mines. The paper has not been peer reviewed. _ In the complete paper, poorly understood leakage potential is researched to quantify the carbon-leakage rate along one legacy well when carbon is injected into a storage formation in the Denver-Julesburg (DJ) Basin. The authors’ results indicate that, for secure carbon sequestration, a good geological storage site should be kept away from wells that have a surface casing depth of 476 ft or shallower and that were drilled before 1994. The effective well permeability highly affects leakage rate, suggesting the importance of estimating the most-representative value or range for this parameter. Introduction To estimate risks associated with geological carbon storage, the National Risk Assessment Partnership (NRAP) Open-Integrated Assessment Model (IAM) tool used in this study presents a modeling approach that can couple efficient reservoir and wellbore components with low computational cost. Two wellbore model components, the open-wellbore model and the multisegmented-wellbore model, were studied to estimate the leakage rate during and after carbon-injection operations. The effective permeability of the disturbed zone outside the well casing is an important parameter in leakage models. However, estimating a reasonable range for the effective well permeability of the disturbed zone remains a challenge. For this study, a more than 1-sq-mile section in the Wattenberg Field of the DJ Basin was used. The goal was to quantify the leakage rate when carbon dioxide (CO2) escapes through a well 1,100 ft from the CO2 injector. First, a reservoir simulation model was built to reflect the pressure and saturation changes during the 30-year injection period and the 100-year postinjection period. This model, based on an ongoing field study, included the CO2 injector, the legacy well that is the potential pathway of CO2 leakage, and the carbon storage formation. Study Area Carbon Storage Potential in Colorado. The top-ranked CO2 emission facilities in Colorado are above the DJ Basin. According to carbon-emission data, 13 facilities in Colorado, including five coal plants, emitted more than 0.7 million tons of CO2 in 2020. All the coal plants are scheduled to be retired by 2034. All eight CO2 emission facilities are in the DJ Basin, with half of those in the Wattenberg Field. This makes the DJ Basin, especially the Wattenberg Field, a good target for carbon storage. The stacked formations of oil and gas reservoirs and saline aquifers in the DJ Basin are potential CO2-storage formations. The current drilling activities with multistage fracture stimulation of horizontal wells target the oil- and gas-producing zones of Niobrara through Greenhorn. These oil and gas producers penetrate the shallower Pierre sandstone formation. This study quantifies the carbon-leakage risk when the Pierre sandstone is the carbon-storage formation and when one nearby Niobrara legacy well penetrates the storage formation and may behave as a potential leakage pathway.

Dynamic estimates of geologic CO2storage resources in the Illinois Basin constrained by reinjectivity of brine extracted for pressure management

AbstractGeologic carbon storage (GCS) is likely to be an important part of global efforts to decarbonize the energy industry. Widespread deployment of GCS relies on strategies to maximize CO2injection rates while minimizing reservoir pressurization that could induce seismicity and/or fluid leakage into groundwater resources. Brine extraction from CO2storage formations with subsurface reinjection elsewhere could mitigate pressure buildup associated with GCS. Therefore, evaluation of CO2storage resources should consider the injectivity of produced brine in geologic layers above or below the CO2storage formation. For this study, a methodology was developed to estimate brine injectivity from formation depth and thickness using flow modeling and optimization techniques. The methodology was demonstrated in the Illinois Basin, where GCS in the Mt. Simon Sandstone is ongoing. Based on pressure constraints and considering only regions of the shallower units where salinity and sealing conditions were met, maximum brine injection rates were estimated within the Mt. Simon and three overlying hydrostratigraphic layers. Results indicate that a large area exists where CO2injectivity could be optimized by brine extraction and reinjection. © 2022 The Authors.Greenhouse Gases: Science and Technologypublished by Society of Chemical Industry and John Wiley & Sons Ltd.

Superabsorbent polymer for improved CO2 hydrate formation under a quiescent system

The hydrate formation rate and conversion yield are essential factors for hydrate-based gas storage and accordingly various thermodynamic and kinetic promoters have been extensively investigated. However, for hydrate-based CO2 capture, carbonate ions induced from dissolved CO2 in water hinder the performance of kinetic promoters (e.g., sodium dodecyl sulfate (SDS)). In this work, we introduce a superabsorbent polymer (SAP) matrix that provides an extremely high interfacial area between a sorbed tetrahydrofuran (THF) solution and gaseous CO2. The SAP enhanced the formation rate of binary THF-CO2 hydrate, despite the absence of mechanical agitation. We varied the concentration of THF, temperature, reactor volume, and the ratio of solution to the reactor for a systematic study and explored their effects on the CO2 storage capacity and the induction time. We observed that highly concentrated THF and a larger reactor with a high gas-liquid contact area enhanced the CO2 storage capacity and formation rate. Raman and PXRD spectroscopic analyses were employed to investigate the guest distribution and crystalline structure of the THF-CO2 hydrates synthesized under various conditions. All the binary hydrates were structure-II (sII) hydrates, and there was no pure structure-I (sI) CO2 hydrate. Based on the spectroscopic results, we developed a theoretical model that could calculate the amount of enclathrated CO2 and dissolved CO2 in liquid phases separately. This work reveals that SAP has excellent potential for rapid CO2 capture in hydrate media with a high water-to-hydrate conversion ratio.

Numerical Modeling of the Injection of Nanoparticles in Saturated Cementitious Material by Electromigration

AbstractThis paper presents numerical modeling of nanoparticles injected into cementitious material using the electromigration method. In order to remediate leaking wells in CO2 storage formations,...

Potential of the Middle Cambrian Aquifer for Carbon Dioxide Storage in the Baltic States

The importance of CO2 removal from the atmosphere has long been an essential topic due to climate change. In this paper, the authors aim to demonstrate the suitability of the underground reservoirs for CO2 storage based on their geological characteristics. The research addressed the potential of geological formations for fossil CO2 storage in the Baltic States to support the goal of achieving carbon neutrality in the region. The geological, technical, and economic feasibility for CO2 storage has been assessed in terms of carbon sequestration in geological structures and the legal framework for safe geological storage of fossil CO2. Results indicate that prospective structural traps in the Baltic States, with reasonable capacity for CO2 storage, occur only in Southwestern Latvia (onshore) and in the Baltic Sea (offshore), whilst other regions in the Baltics either do not meet basic geological requirements, or have no economically feasible capacity for CO2 storage. Based on the examination of geological characteristics, the most fitting is the middle Cambrian reservoir in the Baltic sedimentary basin, and one of the most prospective structural traps is the geological structure of Dobele, with an estimated storage capacity of 150 Mt CO2. This study revealed that the storage capacity of the middle Cambrian reservoir (up to 1000 Mt CO2) within the borders of Southwestern Latvia is sufficient for carbon capture and safe storage for the whole Baltic region, and that geological structures in Latvia have the capacity to store all fossil CO2 emissions produced by stationary sources in the Baltic States for several decades.

A Numerical Analysis of the Effects of Supercritical CO2 Injection on CO2 Storage Capacities of Geological Formations

One of the most promising means of reducing carbon content in the atmosphere, which is aimed at tackling the threats of global warming, is injecting carbon dioxide (CO2) into deep saline aquifers (DSAs). Keeping this in mind, this research aims to investigate the effects of various injection schemes/scenarios and aquifer characteristics with a particular view to enhance the current understanding of the key permanent sequestration mechanisms, namely, residual and solubility trapping of CO2. The paper also aims to study the influence of different injection scenarios and flow conditions on the CO2 storage capacity and efficiency of DSAs. Furthermore, a specific term of the permanent capacity and efficiency factor of CO2 immobilization in sedimentary formations is introduced to help facilitate the above analysis. Analyses for the effects of various injection schemes/scenarios and aquifer characteristics on enhancing the key permanent sequestration mechanisms is examined through a series of numerical simulations employed on 3D homogeneous and heterogeneous aquifers based on the geological settings for Sleipner Vest Field, which is located in the Norwegian part of the North Sea. The simulation results highlight the effects of heterogeneity, permeability isotropy, injection orientation and methodology, and domain-grid refinement on the capillary pressure–saturation relationships and the amounts of integrated CO2 throughout the timeline of the simulation via different trapping mechanisms (solubility, residual and structural) and accordingly affect the efficiency of CO2 sequestration. The results have shown that heterogeneity increases the residual trapping of CO2, while homogeneous formations promote more CO2 dissolution because fluid flows faster in homogeneous porous media, inducing more contact with fresh brine, leading to higher dissolution rates of CO2 compared to those in heterogeneous porous medium, which limits fluid seepage. Cyclic injection has been shown to have more influence on heterogenous domains as it increases the capillary pressure, which forces more CO2 into smaller-sized pores to be trapped and exposed to dissolution in the brine at later stages of storage. Storage efficiency increases proportionally with the vertical-to-horizontal permeability ratio of geological formations because higher ratios facilitate the further extent of the gas plume and increases the solubility trapping of the integrated gas. The developed methodology and the presented results are expected to play key roles in providing further insights for assessing the feasibility of various geological formations for CO2 storage.

Influence of Organic Acid Concentration on Wettability Alteration of Cap-Rock: Implications for CO2 Trapping/Storage.

Every year, millions of tons of CO2 are stored in CO2-storage formations (deep saline aquifers) containing traces of organic acids including hexanoic acid C6 (HA), lauric acid C12 (LuA), stearic acid C18 (SA), and lignoceric acid C24 (LiA). The presence of these molecules in deep saline aquifers is well documented in the literature; however, their impact on the structural trapping capacity and thus on containment security is not yet understood. In this study, we therefore investigate as to how an increase in organic acid concentration can alter mica water wettability through an extensive set of experiments. X-ray diffraction (Figure S2), field emission scanning electron microscopy, total organic carbon analysis, Fourier-transform infrared spectroscopy, atomic force microscopy, and energy-dispersive X-ray spectroscopy were utilized to perceive the variations in organic acid surface coverage with stepwise organic acid concentration increase and changes in surface roughness. Furthermore, thresholds of wettability that may indicate limits for structural trapping potential (θr < 90°) have been discussed. The experimental results show that even a minute concentration (∼10-5 mol/L for structural trapping) of lignoceric acid is enough to affect the CO2 trapping capacity at 323 K and 25 MPa. As higher concentrations exist in deep saline aquifers, it is necessary to account for these thresholds to derisk CO2-geological storage projects.

CO2 mobility reduction using foam stabilized by CO2- and water-soluble surfactants

Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses (Sw∗). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.

CO2-water-rock predictions from aquifer and oil field drill core data: The Precipice Sandstone-Evergreen Formation CO2 storage reservoir-seal pair

SummaryThe Surat Basin is one of the most prospective onshore basins in Australia for CO2 storage. The Precipice Sandstone and Evergreen Formation have been appraised for their feasibility as a future CO2 storage reservoir-seal pair. Here we will focus on predicted CO2-water-rock reactions. These predictions rely on mineral and porosity data from drill core. Data were obtained from northern and two southern regions of the Basin. The northern region was more data rich. The southern region is more well core and data sparse with the exception of the Moonie oil Field. Additional drill core samples were collected from archived well core of Moonie and other parts of the basin. The core samples were characterised for porosity, mineral, and metal content to build geochemical models to predict local CO2-water-rock reactions and their potential effect on reservoir scaling, changes to porosity and mineral trapping of CO2. For the northern region, our work has predicted low reactivity of the Precipice Sandstone, with mineral trapping in the Evergreen Formation. The Precipice Sandstone sampled in the Moonie field has different mineralogical characteristics to wells in the Northern region. Here, CO2-water-rock predictions indicate minor alteration of plagioclase and K-feldspar to kaolinite, chalcedony and ankerite in cleaner Moonie sandstones, with additionally precipitation of smectite in clay rich sands. Formation water pH was buffered between 5 and 6 by dissolution of calcite or siderite cements. Sampled core has also shown evidence of previous natural CO2 and hydrothermal fluid alteration, fractured quartz grains, and fracture fills with mineral trapping as carbonates. This type of natural analogue data is vital to validate long term predictions. New drill core and data are still required in future for the southern and central Surat Basin region which is most prospective for CO2 injection and storage.

The importance of lithofacies control on fluid migration in heterogeneous aeolian formations for geological CO2 storage: Lessons from observational evidence and modelling of bleached palaeoreservoirs at Salt Wash Graben, Utah

Exhumed bleached palaeoreservoirs provide a means of understanding fluid flow processes in geological media because the former movement of fluids is preserved as visible geochemical changes (grey bleaching of continental red-beds). The bleached palaeoreservoirs of the Jurassic Entrada Sandstone occur in a region (Utah) where there are high fluxes of naturally-occurring CO2 and form outcrop analogues for processes related to geological storage of CO2. In this paper a bleached palaeoreservoir now exposed at outcrop is used to test the importance of geological heterogeneity on fluid flow. The bleached palaeoreservoir is developed in ‘wet aeolian’ lithofacies composed of alternating layers of sandstone and cemented muddy sandstone that range across three or more orders of magnitude in permeability. Despite these permeability contrasts the bleaching shows a remarkably uniform distribution within the palaeoreservoir that crosses lithofacies boundaries. Evidence from bleaching therefore suggests that geological heterogeneity within the range 1–103 millidarcies should not greatly impede the relatively uniform distribution of low-viscosity CO2 charged fluids throughout a reservoir: a conclusion that has been substantiated here by flow modelling. Residence time is an important factor and where flows are transient the distribution of bleaching and modelling shows that flows are confined to high-permeability lithofacies.

Transport properties of saline CO2 storage reservoirs with unconnected fractures from brine-CO2 flow-through tests

CO2 storage in fractured reservoirs may lead to fast CO2 flow through interconnected fracture networks; but the role of isolated fractures on brine-CO2 multiphase flow systems remains unclear. We present the results of a brine-CO2 flow-through experiment in which we assess the change in transport properties of a synthetic sandstone plug (a surrogate of a saline siliciclastic CO2 reservoir) containing non-connected fractures aligned 45° from its axis. The test was performed at 40 MPa of constant hydrostatic confining pressure and ~11 MPa of pore pressure, at room temperature (~19.5 °C), using pure liquid-CO2 and 35 g L−1 NaCl salt solution. The injected CO2-brine volume fraction was increased from 0 to 1 in 0.2 units-steps (drainage). Upon achievement of the maximum CO2 saturation (SCO2 ~0.6), the plug was flushed-back with the original brine (imbibition). During the test, we monitored simultaneously pore pressure, temperature, axial and radial strains, and bulk electrical resistivity. The fractured sample showed lower values of cross- and end-points in the relative permeability curves to CO2 compared to non-fractured samples, from comparable experiments performed at similar pressure and brine salinity conditions, but different temperature. Our results suggest that a non-connected fracture network affects the mobility of the individual phases, favouring the trapping of CO2 in the porous medium and improving the storage efficiency of the reservoir. These evidences show the need of a better understanding of fracture connectivity prior to discard fractured reservoirs as unsuitable geological formations for CO2 storage.

Analogue modelling of leakage processes in unconsolidated sediments

Cenozoic sedimentary basins typically contain young, unconsolidated sediments, potentially suitable for CO2 storage, e.g. the Utsira sand in the Norwegian North Sea Basin. During burial and compaction, formation fluids are squeezed out of the sedimentary deposits. These fluids can mobilize and transport sediments to overlying strata, forming seismic-scale clastic intrusions and shallow gas accumulations, to the Earth’s surface, or to the sea floor, where they are expelled through pockmarks or mud volcanoes, respectively. These deformation processes are described as subsurface sediment remobilization (SSR). Little attention has been paid to the formation mechanisms of SSR in the search for CO2 storage formations, though they may be relevant for storage safety, either occurring naturally, triggered by CO2 injection, or being fossil features providing pathways for fluid migration in the subsurface. Structural characteristics of SSR features are well known, but formation processes and dynamics are poorly understood. We have developed a scaled analogue experimental approach and performed systematic laboratory experiments in order to comprehend and quantify the conditions controlling and triggering SSR, the critical rheological properties of sediments, and storage structures (layer thickness, anticlines, faults). Experimental results are presented and potential implications for the selection of storage sites and storage safety are discussed in this article.