Simple estimation methodology of leakage from geologic storage of CO2 (original) (raw)
Related papers
Simple estimation methodology of leakage from ocean storage of CO2 for policy makers
Greenhouse Gas Control Technologies 7, 2005
The objective of this paper is to develop a simple methodology to estimate amount of such leakages, which can be utilized by those who do not have sufficient simulation resources, in order to create a basis for CCS accounting. We develop leak estimation methodology based on quality of cap rocks (seal quality). To quantify quality of cap rocks, we newly developed Cap-rock Quality Factors (CQF). CQF is calculated reflecting features of site, height of cap rock, depth of the site and possibility of three types of leakage, leakage via matrix of cap-rock, leakage via fracture of cap-rock, and leakage via wells. We use two different interpretations of CQF, Conduit Model and Membrane Model, to estimate amount of leakage by category of cap-rock (seal) quality. Conduit Model can be generally applicable to "certain structural seal" category and Membrane Model applicable to "uncertain seal" category.
Towards a methodology for top seal efficacy assessment for underground CO2 storage
Greenhouse Gas Control Technologies 7, 2005
Quantitative assessment of leakage risk and leakage rates from planned underground CO 2 storage sites is a primary requirement for public acceptance, formal site approval, and credit for stored CO 2 quantities under CO 2 emission schedules. Leakage through the top seal can basically occur by three processes: (i) diffusion through the pore system, (ii) capillary transport through the pore system of the seal, (iii) multiphase migration through a (micro-) fracture network; or by a combination of any of these. Diffusion results in very low leakage rates; maximum rates typically attained after several 100000 years, being in the ppm range. Multiphase capillary migration is characterized by two main parameters: capillary breakthrough pressure and effective permeability to the non-wetting phase (CO 2). The dependence of effective permeability to CO 2 on capillary pressure, which in turn is a function of CO 2 column height, is hysteretic in character with generally higher effective permeability during pressure decrease (column shrinkage) than during increase, at the same capillary pressure (CO 2 column height). Leakage is likely to stop at approximately 20 to 50% of the breakthrough pressure as suggested by the 'snap-off' theory by Vassenden et al. (2003). Capillary breakthrough pressure and effective permeability is very difficult to measure for low-permeable rocks. A recently presented method by Hildenbrand et al. (2002) shows promising results, but their data require cautious re-interpretation prior to application to CO 2-storage cases. Time-delay effects may imply that their 'maximum effective permeability' at laboratory conditions is not the maximum attainable in nature and in CO 2 storage reservoirs. Their 'minimum capillary displacement pressure' may rather be a 'snap-off' pressure than a breakthrough pressure, the latter being higher by a factor of 2 to 5. Detection and prediction of the presence of microfractures, which have much larger permeability than the rock matrix, is difficult. Simulation techniques can, however, be used to estimate the likelihood for their generation by burial-induced overpressure. In general, prediction of fluid-flow parameters for the seal to CO 2 storage sites is a challenge due to the probable low data coverage. Reliable extrapolation of such parameters from punctual data at wells across the space above the whole storage site requires considerable improvements of the understanding of depositional processes of fine-grained rocks.
International Journal of Greenhouse Gas Control
Numerical models of geologic carbon sequestration (GCS) in saline aquifers use multiphase fluid flow-characteristic curves (relative permeability and capillary pressure) to represent the interactions of the non-wetting CO2 and the wetting brine. Relative permeability data for many sedimentary formations is very scarce, resulting in the utilisation of mathematical correlations to generate the fluid flow characteristics in these formations. The flow models are essential for the prediction of CO2 storage capacity and trapping mechanisms in the geological media. The observation of pressure dissipation across the storage and sealing formations is relevant for storage capacity and geomechanical analysis during CO2 injection. This paper evaluates the relevance of representing relative permeability variations in the sealing formation when modelling geological CO2 sequestration processes. Here we concentrate on gradational changes in the lower part of the caprock, particularly how they affect pressure evolution within the entire sealing formation when duly represented by relative permeability functions. The results demonstrate the importance of accounting for pore size variations in the mathematical model adopted to generate the characteristic curves for GCS analysis. Gradational changes at the base of the caprock influence the magnitude of pressure that propagates vertically into the caprock from the aquifer, especially at the critical zone (i.e. the region overlying the CO2 plume accumulating at the reservoir-seal interface). A higher degree of overpressure and CO2 storage capacity was observed at the base of caprocks that showed gradation. These results illustrate the need to obtain reliable relative permeability functions for GCS, beyond just permeability and porosity data. The study provides a formative principle for geomechanical simulations that study the possibility of pressure-induced caprock failure during CO2 sequestration.
The Leakage Impact Valuation (LIV) Method for Leakage from Geologic CO2 Storage Reservoirs
2013
Leakage of brine or carbon dioxide (CO 2 ) from geologic CO 2 storage reservoirs will trigger numerous costs. We present the Leakage Impact Valuation (LIV) method, a systematic and thorough scenario-based approach to identify these costs, their drivers, and who incurs them across four potential leakage outcomes: 1) Leakage only; 2) leakage that interferes with a subsurface activity; 3) leakage that affects groundwater; and 4) leakage that reaches the surface. The LIV method is flexible and can be used to investigate a wide range of scenarios. The financial consequences of leakage estimated by the LIV method will be specific to the case study, because the consequences of leakage will vary across case studies due to differences geologic, institutional, and regulatory settings.
Modelling and Simulation of Mechanisms for Leakage of CO2 from Geological Storage
Energy Procedia, 2009
For investigation of the risks associated with future geological storage of CO 2 , and for determining the minimum requirements for the quality of geological storage sites, detailed study of possible leakage mechanisms is necessary. Mechanisms for potential leakage from primary CO 2 storage in deep saline aquifers have been studied. A buoyancy-driven flow of CO 2 through a percolating network of permeable bodies in an otherwise sealing cap-rock has been simulated on a geological model of the overburden composed of geological features characteristic for a marine sediments. Channels and lobes from turbidite flows are significant constituents to form a possible leakage pathway in this study.
Energy Exploration & Exploitation, 2014
Geological storage of CO2 is considered widely as an efficient method of mitigation of greenhouse gas emission. CO2 storage mechanism includes structural trapping, residual gas trapping, solubility trapping and mineral trapping. The shale cap rock acts as a seal for the storage when CO2 accumulates at the top of the reservoir. The injected CO2 may migrate through the cap rock under buoyancy force or pressure build-up which depends on the seal capacity of the cap rock. As a result, the effectiveness of containment of injected CO2 in the reservoir is largely dependent on the migration rate of CO2 through the cap rock. This paper investigates the effects of CO2 leakage through cap rock by a combination of experimental studies and numerical simulation. Firstly, experimental measurements on shale core samples collected from Australian cap rocks were conducted to determine properties, such as capillary pressure, pore size distribution and permeability. Based on the measured cap rock prope...
Energy Procedia, 2017
The Aliso Canyon gas well leakage is used as an analogue to study a possible accident from a CO2 storage site. Because the blowout is the second largest in USA, it can be used as a worst-case blowout analogue for a possible CO2 blowout from an underground CO2 storage. Reservoir modelling and well modelling of the Aliso Canyon case is used to determine the leakage pathway and leakage mechanisms that will mimic the escape history. This data are put in a new model where the gas is replaced by CO2 and a similar accident is simulated. Several factors are different between gas leakage from gas storage and potential leakage from a typical CO2 storage in an aquifer, due to differences in thermodynamic properties and flow properties both along in the leakage pathway and in the porous medium in the storage reservoir. The specific features of the two cases are compared and show that as the risk elements are very different, remediation measures will be different. The escape rate is significant lower for the CO2 scenario than the observed gas escape from Aliso Canyon gas well (4.9 Sm 3 /s respectively 21.3 Sm 3 /s). While 2.8 % of the stored gas was lost at the Aliso Canyon leak, the corresponding loss from a CO2 well if the facility was used for CO2 storage would be 0.37%. Due to the high density of CO2, the well pressure at the rupture was less than half than for CO2 compared to gas, which will make remediation easier.
Energy Procedia, 2010
The Certification Framework (CF) is a simple risk assessment approach for evaluating CO2 and brine leakage risk at geologic carbon sequestration (GCS) sites. In the In Salah CO2 storage project assessed here, five wells at Krechba produce natural gas from the Carboniferous C10.2 reservoir with 1.7–2% CO2 that is delivered to the Krechba gas processing plant, which also receives high- CO2 natural gas (∼10% by mole fraction) from additional deeper gas reservoirs and fields to the south. The gas processing plant strips CO2 from the natural gas that is then injected through three long horizontal wells into the water leg of the Carboniferous gas reservoir at a depth of approximately 1,800 m. This injection process has been going on successfully since 2004. The stored CO2 has been monitored over the last five years by a Joint Industry Project (JIP)–a collaboration of BP, Sonatrach, and Statoil with co-funding from US DOE and EU DG Research. Over the years the JIP has carried out extensive analyses of the Krechba system including two risk assessment efforts, one before injection started, and one carried out by URS Corporation in September 2008. The long history of injection at Krechba, and the accompanying characterization, modeling, and performance data provide a unique opportunity to test and evaluate risk assessment approaches. We apply the CF to the In Salah CO2 storage project at two different stages in the state of knowledge of the project: (1) at the pre-injection stage, using data available just prior to injection around mid-2004; and (2) after four years of injection (September 2008) to be comparable to the other risk assessments. The main risk drivers for the project are CO2 leakage into potable groundwater and into the natural gas cap. Both well leakage and fault/fracture leakage are likely under some conditions, but overall the risk is low due to ongoing mitigation and monitoring activities. Results of the application of the CF during these different state-of-knowledge periods show that the assessment of likelihood of various leakage scenarios increased as more information became available, while assessment of impact stayed the same. Ongoing mitigation, modeling, and monitoring of the injection process is recommended.
Quick Caprock Integrity Analysis for CO2 Storage Sites in Malaysian Fields
Day 1 Tue, November 17, 2020, 2020
The purpose of this research work is to establish a quick method for caprock integrity assessment for carbon dioxide (CO2) storage site selection. There are three main components to evaluate a seal potential which are through seal capacity, seal geometry, and seal integrity. This research work focuses on evaluation of seal characteristics through its pressure behaviour and evidence of potential leakage. Various logs data such as gamma ray, sonic logs, density logs, and resistivity are utilized to establish 1D pore pressure analysis. At the same time mud logs data are used to investigate the similarity of hydrocarbon from reservoir and seal (if any). In this study, two mature brownfields namely Camos and Zhann have been identified and evaluated for their seal characteristics, thickness, environment of deposition and pressure regimes differences in order to determine their seal effectiveness through integration of pore pressure analysis, background gas or gas while drilling evidence a...