Figure 5 - uploaded by Francesco Zarlenga
Content may be subject to copyright.
Source publication
Underground accumulation of carbon dioxide (CO2) is a widespread geological phenomenon, with natural trapping of CO2 in underground reservoirs. Information and experience gained from the injection and/or storage of CO2 from a large number
of existing enhanced oil recovery (EOR) and acid gas projects, as well as from the Sleipner, Weyburn and In Sal...
Similar publications
Wichita Falls, TX, USA. Misurata, Libya Wichita Falls, TX, USA. Wichita Falls, TX, USA. Wichita Falls, TX, USA. Abstract-Darcy and non-Darcy flow through packing particles is an important study to determine the flow rate and pressure drop through porous media. Darcy is formed with a low liquid flow rate while the non-Darcy flow is formed with a hig...
Citations
Carbon Capture Utilization and Storage (CCUS) has been recognized as a tool to aid the decarbonisation of carbon heavy industries, with the storage of CO2 in the subsurface over geological timescales being a key component in the CCUS process chain. Assessing and managing the risks involved in subsurface storage of CO2 is required so decisions can be made about the design, operation, monitoring and acceptability of potential projects. As with existing industrial activities, a number of approaches exist for assessing risk ranging from purely qualitative approaches through to quantitative approaches.
A structured, proportional risk assessment approach is proposed, aimed at identifying, analysing and evaluating the risk from a candidate subsurface store through a combination of qualitative and quantitative techniques to gain the most benefit. Development of a register of subsurface containment risks allows for the identification of scenarios of concern, which can be coupled with risk matrices to provide an estimation of the risk level together with its acceptability. More in depth qualitative techniques such as bowtie analysis encourage different disciplines to collaborate and enhance communication, both internally and externally, of the controls present for the most significant risks. The combination of bowties with a quantified, event tree-based model can allow for numerical determination of leakage probability and magnitude. Quantitative methods can therefore estimate insurance liabilities and allow comparison of options or with acceptance criteria. However, these assessments are underpinned by the quality of inputs. Given that the CCUS industry is still in its infancy, data surrounding event likelihoods and leak magnitudes, especially for geological leakage pathways, can have large amounts of associated uncertainty; this uncertainty must be taken into account when evaluated the overall acceptability of projects. Whilst both quantitative and qualitative methodologies for risk assessing subsurface CO2 storage have their advantages and disadvantages, it is when combined as part of a structured CCUS risk assessment approach that the most benefit is gained.
We evaluate the CO2 storage potential for the depositional environments of the West Siberian sedimentary basin. Particularly, we investigate the prospect of storing large volumes of CO2 in the alluvial fan, barrier island, deltaic, and fluvial environments. We employ several detailed 3-D models of petroleum reservoirs as proxies for the saline aquifers occurring in the basin under the listed environments. By simulating supercritical CO2 injection into several reservoir sectors, we compare the environments in terms of their prospects for the underground storage of CO2. We estimate the maximum capacity and storage potential for the entire sectors by considering them the resources licensed for an industrial-scale Carbon Capture and Storage (CCS) project. The scenarios with a single and multiple injection wells are assessed in the evaluation, which might be of interest for the elaboration of feasible regulations and policies in the area. We find out that the barrier island deposits are characterized by maximum potential, whereas the fluvial environments are the least suitable for deploying CCS. We demonstrate that for the barrier island environments, the storage potential is most sensitive to the relative permeability end-points. We also test several scaling concepts for extending our estimates for a single-well injection to a multi-well scenarios and generally from a site-specific to regional scale. We conclude that due to the interference between nearby wells, the storage potential for a single well scenario cannot reliably be scaled to the case of CO2 injection through a group of wells.
The success of CCS depends on the capacity, injectivity, and confinement by the storage medium. Thousands of wells drilled over the past century with the intention to find the trapped oil and gas may penetrate the containment seals. These wells may provide leakage pathways for the CO2 to escape and contaminate the underground sources of drinking water (USDW) or reach the surface in the worst-case scenario. Identifying the risky wells penetrating the containment seals and predicting their current as well as future well integrity is the most challenging task when limited data is available. This paper proposes a unique methodology for risk assessment of the wells penetrating the containment seals based on the proximity of these wells from the proposed injection location, mechanical integrity, and accessibility of these wells over the lifecycle of the CCS project. This helps in identifying the wells which need immediate attention from the wells that need little to no attention. It also highlights the corrective actions necessary for the success of the CCS project as well as help estimate the approximate cost required to perform the corrective actions. This methodology focuses on all wells (producers, injectors, orphan, abandoned, water, stratigraphic, etc) while the majority of the studies found in literature focused on wells with sustained casing pressure (SCP) reports and cement bond logs (CBL). The proposed risk matrix, if applied to future CCS projects across the globe, will uniformly categorize the wells within the Area of Review (AoR).
Due to the combined advantages of injecting CO2 for boosting natural gas recovery efficiency and sequestration of CO2 in depleted shale gas reservoirs, the enhanced gas recovery (EGR) approach has recently attracted the attention of researchers. To analyze the viability of the increased gas recovery technique, many published studies were reviewed based on theoretical, experimental settings, and simulation models in this manuscript. The underlying link between geological and petrophysical factors is discussed, as well as how they affect CO2 and CH4 sorption. According to numerous studies, 30–55 percent of the CO2 injected into the shales is adsorbed on the pores surface of the rock matrix, resulting in CH4 desorption and additional natural gas recovery of 8–16 percent. For the application in diverse shales reservoir conditions, the best fit adsorption models (Langmuir, Ono Kondo, and D-A) were summarized. The theoretical findings of this work are anticipated to add to current studies on CO2 adsorption and sequestration, as well as CH4 desorption characteristics and the myriad simulation studies have revealed that well spacing, fracture permeability, injection pressure and strategies are key consideration for effective field demonstration for CO2-EGR projects. Despite the availability of theoretical explanations, experimental verification, and modeling findings, field-scale trials remain limited due to the risk of CO2–CH4 mixing and the high cost of capturing, purifying, and re-injecting CO2 into depleted reservoirs. Furthermore, the unpredictable heterogeneity of the shale formation still poses challenges on the gas recovery. The setbacks and limitations highlighted in this study will encourage academia and researchers to conduct more research into appropriate EGR technologies and their economic implications.
Net fluid balance in the Alberta Basin has been negative over the last 60 years because extensive fluid production has consistently exceeded injection during this period. However, future gigaton-scale carbon sequestration, among other activities, can result in future cumulative fluid injection exceeding extraction (i.e., a positive net fluid balance). The in-situ net fluid balance (i.e., total fluids produced minus total fluids injected) in this basin over the period 1960–2020 shows that a liquids deficit of 4.53x109 m3 and a gas deficit of 6.05x1012 m3 currently exist. However, fluid deficits are more significant in the upper stratigraphic intervals (located more than 1 km above the Precambrian Basement) than in the stratigraphic intervals located within 1 km of the Precambrian Basement in most geographic regions. This observation indicates that greater sustainable injection capacity for large-scale fluid injection may exist in the upper stratigraphic intervals (located at more than 1 km above the Precambrian Basement), reducing the potential for generating induced seismicity of concern. Additionally, while fluid depletion rates consistently increased over most of the last 60 years in the Alberta Basin, this trend appears to have changed over the past few years. Such analysis of regional net fluid balance and trends may be useful in assessing regional sustainable fluid storage capacity and managing induced seismicity hazards.
Supercritical carbon dioxide injection in tight reservoirs is an efficient and prominent enhanced gas recovery method, as it can be more mobilized in low-permeable reservoirs due to its molecular size. This paper aimed to perform a set of laboratory experiments to evaluate the impacts of permeability and water saturation on enhanced gas recovery, carbon dioxide storage capacity, and carbon dioxide content during supercritical carbon dioxide injection. It is observed that supercritical carbon dioxide provides a higher gas recovery increase after the gas depletion drive mechanism is carried out in low permeable core samples. This corresponds to the feasible mobilization of the supercritical carbon dioxide phase through smaller pores. The maximum gas recovery increase for core samples with 0.1 mD is about 22.5%, while gas recovery increase has lower values with the increase in permeability. It is about 19.8%, 15.3%, 12.1%, and 10.9% for core samples with 0.22, 0.36, 0.54, and 0.78 mD permeability, respectively. Moreover, higher water saturations would be a crucial factor in the gas recovery enhancement, especially in the final pore volume injection, as it can increase the supercritical carbon dioxide dissolving in water, leading to more displacement efficiency. The minimum carbon dioxide storage for 0.1 mD core samples is about 50%, while it is about 38% for tight core samples with the permeability of 0.78 mD. By decreasing water saturation from 0.65 to 0.15, less volume of supercritical carbon dioxide is involved in water, and therefore, carbon dioxide storage capacity increases. This is indicative of a proper gas displacement front in lower water saturation and higher gas recovery factor. The findings of this study can help for a better understanding of the gas production mechanism and crucial parameters that affect gas recovery from tight reservoirs.
As a new “sink” of CO2 permanent storage, the depleted shale reservoir is very promising compared to the deep saline aquifer. To provide a greater understanding of the benefits of CO2 storage in a shale reservoir, a comparative study is conducted by establishing the full-mechanism model, including the hydrodynamic trapping, adsorption trapping, residual trapping, solubility trapping as well as the mineral trapping corresponding to the typical shale and deep saline aquifer parameters from the Ordos basin in China. The results show that CO2 storage in the depleted shale reservoir has merits in storage safety by trapping more CO2 in stable immobile phase due to adsorption and having gentler and ephemeral pressure perturbation responding to CO2 injection. The effect of various CO2 injection schemes, namely the high-speed continuous injection, low-speed continuous injection, huff-n-puff injection and water alternative injection, on the phase transformation of CO2 in a shale reservoir and CO2-injection-induced perturbations in formation pressure are also examined. With the aim of increasing the fraction of immobile CO2 while maintaining a safe pressure-perturbation, it is shown that an intermittent injection procedure with multiple slugs of hug-n-puff injection can be employed and within the allowable range of pressure increase, and the CO2 injection rate can be maximized to increase the CO2 storage capacity and security in shale reservoir.
