Carbon Capture And Geological Storage Research Articles

Optimization of Relief Well Design Using Artificial Neural Network during Geological CO2 Storage in Pohang Basin, South Korea

This study aims at the development of an artificial neural network (ANN) model to optimize relief well design in Pohang Basin, South Korea. Relief well design in carbon capture and geological storage (CCS) requires complex processes and excessive iterative procedures to obtain optimal operating parameters, such as CO2 injection rate, water production rate, distance between the wells, and pressure at the wells. To generate training and testing datasets for ANN model development, optimization processes for a relief well with various injection scenarios were performed. Training and testing were conducted, where the best iteration and regression were considered based on the calculated coefficient of determination (R2) and root mean square error (RMSE) values. According to validation with a 20-year injection scenario, which was not included in the training datasets, the model showed great performance with R2 values of 0.96 or higher for all the output parameters. In addition, the RMSE values for the BHP and the trapping mechanisms were lower than 0.04. Moreover, the location of the relief well was reliably predicted with a distance difference of only 20.1 m. The ANN model can be robust tool to optimize relief well design without a time-consuming reservoir simulations.

Estimates of CO2 leakage along abandoned wells constrained by new data

The viability of carbon capture and geological storage (CCS) projects depends in part on the risk that injected CO2 or displaced pore fluid will leak out of the target formation into surrounding formations or to the surface. Abandoned oil and gas wells, of which millions exist both throughout the United States and globally, form a potential conduit for this leakage. Recently, specific field measurements have been made to quantify the range of effective permeabilities that can be expected in abandoned wells, enabling us to, for the first time, combine field-scale numerical simulations of CO2 sequestration in deep saline aquifers with real data on effective permeabilities of leaky wells. Using a previously developed semi-analytical reservoir simulator that can accommodate an arbitrary sequence of alternating aquifers and aquicludes, as well as an arbitrary number of leaky wells, we investigated how the amount of CO2 that leaks out of the target formation depends on the spatial density of nearby abandoned wells and their effective permeability. Furthermore, we assess the influence that variations in pressure and temperature found between geological targets have on this dependency. We find that the observed differences in leakage between geological targets are controlled almost exclusively by differences in density of CO2 at the local subsurface conditions, causing the CO2 plume to contact a different number of wells when injecting at the same constant mass rate. We quantitatively assess the results obtained from our numerical experiments by combining them with the permeability data that have recently become available, typical spatial densities of abandoned wells, and performance requirements put forward in the literature. Our results indicate that leakage of CO2 through abandoned wells is unlikely to be a major limitation in storage security of CCS projects.

Uncertainty in risk issues for carbon capture and geological storage: findings from a structured expert elicitation

Carbon capture and geological storage (CCS) is identified within the portfolio of mitigation options for climate change. Each value chain activity of large scale integrated projects (capture, trans...

Placing hubs in CO2 pipelines: An application to industrial CO2 emissions in the Iberian Peninsula

Carbon capture and geological storage (CCS) is a key technology for the World deep decarbonization. However, several challenges remain, such as the optimization of the carbon transportation infrastructures. This study proposes a methodology that applies the Kernel Density function in a geographic information system software and uses as input, CO2 emission sources data to identify emission clusters and emission high-density hotspots. The main goal of the proposed methodology is to perform a preliminary screening to identify areas of interest to install hubs when designing an optimized CO2 pipeline network. The methodology includes an estimation of capturable CO2 emissions and a density analysis that was based on Kernel Density function from the ArcGIS Desktop 10. The methodology was applied to the Iberian Peninsula CO2 industrial emission sources such as refineries, coal and natural gas power plants and cement factories (case study) and the results showed that in Portugal, CO2 industrial emissions reduction can reach up to 68% and, in Spain, up to 74% of CO2 industrial emissions, could be avoided. These are called capturable CO2 emissions which means that they are the portion of the total emissions that can be captured from industrial processes before they reach the atmosphere. Moreover, hubs were shown to be more viable when Portugal and Spain are considered together, therefore, carbon routes (pipeline network) in the future may consider an integrated route for the Iberian Peninsula.

Determining noble gas partitioning within a CO2–H2O system at elevated temperatures and pressures

Quantifying the distribution of noble gases between phases is essential for using these inert trace gases to track the processes controlling multi-phase subsurface systems. Here we present experimental data that defines noble gas partitioning for two phase CO2–water systems. These are at the pressure and temperature range relevant for engineered systems used for anthropogenic carbon capture and geological storage (CCS) technologies, and CO2-rich natural gas reservoirs (CO2 density range 169–656kg/m3 at 323–377K and 89–134bar). The new partitioning data are compared to predictions of noble gas partitioning determined in low-pressure, pure noble gas–water systems for all noble gases except neon and radon. At low CO2 density there was no difference between measured noble gas partitioning and that predicted in pure noble gas–water systems. At high CO2 density, however, partition coefficients express significant deviation from pure noble gas–water systems. At 656kg/m3, these deviations are −35%, 74%, 113% and 319% for helium, argon, krypton and xenon, respectively. A second order polynomial fit to the data for each noble gas describes the deviation from the pure noble gas–water system as a function of CO2 density. We argue that the difference between pure noble gas–water systems and the high density CO2–water system is due to an enhanced degree of molecular interactions occurring within the dense CO2 phase due to the combined effect of inductive and dispersive forces acting on the noble gases. As the magnitude of these forces are related to the size and polarisability of each noble gas, xenon followed by krypton and argon become significantly more soluble within dense CO2. In the case of helium repulsive forces dominate and so it becomes less soluble as a function of CO2 density.

Opportunities and obstacles for CO2 mineralization: CO2 mineralization specific frames in the interviews of Finnish carbon capture and storage (CCS) experts

Carbon capture and storage (CCS) is expected to significantly reduce carbon dioxide (CO2) emissions for climate change mitigation purposes. Currently, the EU CCS Directive contains only geological storage as the storage option for CO2 – excluding CO2 mineralization as a storage option. Since all CCS technologies are currently in a relatively early stage of development, this exclusion seems unreasonable. Opportunities for the use of CO2 mineralization and the main uncertainties that can potentially prevent the use of these opportunities are investigated in this paper. The analysis is done by means of framing methodology that enables the extraction of CCS experts' mental models concerning CO2 mineralization from the interview data.Four of the six frames found hold a quite pessimistic future for CO2 mineralization. In addition, these frames were clearly strengthened when viewed within the global context. The way experts discuss CCS largely frames it in terms of carbon capture and geological storage (CCGS) and pushes CO2 mineralization to the margins. Thus CO2 mineralization is becoming even less likely to be included in policy making. At the same time, the slow progress of CCGS together with low public trust for the safety and sustainability of geological storage could strengthen the optimism found in two expert frames. Eventually this could weaken the pessimistic views and thus lead towards a more optimistic future for CO2 mineralization. However, this would require significant progress in CO2 mineralization technologies and especially increased publicity for such progress.

Carbon capture and geological storage in Brazil: an overview

AbstractBrazil is recognized for possessing a low carbon‐intensive energy matrix, with most of its power being generated from hydroelectricity. Its greenhouse gas emissions profile is dominated by deforestation and land‐use change. Despite this characteristic, the country has been committed to the development of carbon capture and geological storage (CCS) research since this technology started to be recognized as a relevant solution for greenhouse gas emission reductions. This development has gained attention recently owing to the beginning of the production of pre‐salt reservoirs, which may contain significant amounts of CO2 in the produced fluids. The work has been carried out mostly through the efforts of the academia and industrial enterprises. This paper presents a summary and a brief description of the recent activities being carried out by these sectors, aiming to develop and promote CCS in Brazil.

Preliminary Investigation on the Chemical Response of Cementitious Grouts Used for Borehole Sealing of Geologically Stored CO2

Cement-based materials are a vital part of active or abandoned CO2 injection wells and their chemical and mechanical stability is a prerequisite for a wider implementation of carbon capture and geological storage (CCGS). Previous research has revealed the diffusion-controlled alteration mechanisms of various cementitious grouts in CO2-rich environments at various regimes of temperatures, pressures, salinities and pH. In the present paper the main focus are the chemical interactions between a realistic CO2-saturated pore-water (Utsira formation) with class G cement samples at 8MPa for two bottom-hole temperatures (333K, 393K). The carbonation front at 393K was doubled in depth in comparison to 333K, though for both temperatures the overall cement microstructure appeared to remain relatively intact with probable good sealing capacity for properly cemented abandoned wells. Calcium leaching depths for both 333K and 393K were almost identical, with the higher temperature showing evidence of generation of additional barriers to further CO2 inflow. Finally, chloride penetration was found to be independent of the carbonation reactions.

Carbon Capture and Geological Storage (CCS) in Brazil as a Project under the Clean Development Mechanism (CDM)

The carbon capture and geological storage technology (CCGS) is an efficient way of reducing emissions of greenhouse gases. With the inclusion of CCGS as Clean Development Mechanism (CDM) project activity, companies will invest more on CCGS projects due to the possibility of generating Certificated Emission Reduction (CER). This paper study the economic feasibility of a CCGS project as a CDM activity, applied to the Campos Basin in Brazil, considering all annual costs related to capture, transport and storage and the revenue originated from the sale of CERs and the extra oil that only could be produced through enhanced oil recovery (EOR).

Abandoned well CO2 leakage mitigation using biologically induced mineralization: current progress and future directions

AbstractMethods of mitigating leakage or re‐plugging abandoned wells before exposure to CO2are of high potential interest to prevent leakage of CO2 injected for geologic carbon sequestration in depleted oil and gas reservoirs where large numbers of abandoned wells are often present. While CO2resistant cements and ultrafine cements are being developed, technologies that can be delivered via low viscosity fluids could have significant advantages including the ability to plug small aperture leaks such as fractures or delamination interfaces. Additionally there is the potential to plug rock formation pore space around the wellbore in particularly problematic situations. We are carrying out research on the use of microbial biofilms capable of inducing the precipitation of crystalline calcium carbonate using the process of ureolysis. This method has the potential to reduce well bore permeability, coat cement to reduce CO2–related corrosion, and lower the risk of unwanted upward CO2 migration. In this spotlight, we highlight research currently underway at the Center for Biofilm Engineering (CBE) at Montana State University (MSU) in the area of ureolytic biomineralization sealing for reducing CO2 leakage risk. This research program combines two novel core testing systems and a 3‐dimensional simulation model to investigate biomineralization under both radial and axial flow conditions and at temperatures and pressures which permit CO2 to exist in the supercritical state.This combination of modelling and experimentation is ultimately aimed at developing and verifying biomineralization sealing technologies and strategies which can successfully be applied at the field scale for carbon capture and geological storage (CCGS) projects. © 2013 Society of Chemical Industry and John Wiley & Sons, Ltd

Brazilian potential for CCS for negative balance emission of CO2 from biomass energy

Abstract In this work is assessed the Brazilian potential for Carbon Capture and Geological Storage (CCS) through CO 2 capture from biomass sources with focus on bioethanol production facilities. In the present document their geographic distribution is associated with localization of the sedimentary basins as well as the potential geologic reservoirs for CCS is presented, thus providing concrete basis to define and optimize longer term goals, consistent with Brazil’s volunteer commitment to help mitigate the effects of global climate change. It was found that USA, England, Canada, Australia, Germany, France, Netherlands and Japan not only are quite active in the research and technologic development, but also have strong relationships between them, owning several joint products. Historic data point out an increase in ethanol annual production in the last years, being produced mainly by Sao Paulo (61% of the domestic production). The CO 2 emissions were estimated for each Brazilian state based on the ethanol production and the CO 2 emissions due to the fermentation process. There were 26,959,209 m 3 of total ethanol produced, corresponding to about 11.2 billion m 3 of CO 2 emissions at 20 °C and 1 atm, and to about 29 million m 3 of CO 2 in reservoir conditions. The CCS scenarios were built considering porosity in the range from 18% to 24%, using the average of the Brazilian basins for oil production. The Parana Basin should receive over twenty million m 3 of CO 2 , encompassing eight Brazilian states, which requires from 110 to 147 million m 3 of rock. Other Basins, such as Ceara, Marajo or Maranhao, Pelotas, Potiguar, Reconcavo or SEAL, and Tacutu require from 12 to 10,861 thousand m 3 of rock, having each one a specific requirement. In all scenarios, the rock volumes are smaller than the real Basins volume, thus a very favorable negative balance can be achieved for bioethanol.

The challenges on the CCGS monitoring in the development of Santos Basin Pre-salt Cluster

The Santos Basin Pre-salt reservoirs are located in deepwater offshore Brazil and although the oil has a good quality, their CO2 concentrations are higher than those generally found in other Brazilian fields. PETROBRAS and its partners established that they will not vent the CO2 produced in the Pre-salt layer to the atmosphere so a CO2 injection scenario is a potential alternative to improve the oil recovery. An extensive monitoring program is being considered in order to ensure the Carbon Capture and Geological Storage (CCGS) projects efficiency. However, there are several challenges to be confronted concerning the CO2 monitoring in such adverse conditions as the Pre-salt reservoirs. Among the existing techniques for monitoring offshore storage sites, some of them have already technological maturity and applicability to the Pre-salt environment but other methods must rely on some development or methodology adaptation to the specific features of these fields and they will be initiatives of the PRO- CO2 technological program of PETROBRAS Research Center. This paper addresses the main technological challenges for PETROBRAS and its partners related to the methods applicability for the CO2 storage monitoring in the Santos Basin Pre-salt Cluster and also exposes the strategies found to solve the problems.

Field-scale application of a semi-analytical model for estimation of CO 2 and brine leakage along old wells

Carbon capture and geological storage (CCS) operations will require an environmental risk analysis to determine, among other things, the risk that injected CO 2 or displaced brine will leak from the injection formation into other parts of the subsurface or surface environments. Such an analysis requires site characterization including identification of potential leakage pathways. In North America, the century-long legacy of oil and gas exploration and production has left millions of oil and gas wells, many of which are co-located with otherwise good geological storage sites. Potential leakage along existing wells, coupled with layered stratigraphic sequences and highly uncertain parameters, makes quantitative analysis of leakage risk a significant computational challenge. However, new approaches to modeling CO 2 injection, migration, and leakage allow for realistic scenarios to be simulated within a probabilistic framework. Using a specific field site in Alberta, Canada, we perform a range of computational studies aimed at risk analysis with a focus on CO 2 and brine leakage along old wells. The specific calculations focus on the injection period, when risk of leakage is expected to be largest. Specifically, we simulate 50 years of injection of supercritical CO 2 and use a Monte Carlo framework to analyze the overall system behavior. The simulations involve injection, migration, and leakage over the 50-year time horizon for domains of several thousand square kilometers having multiple layers in the sedimentary succession and several thousand old wells within the domain. Because we can perform each simulation in a few minutes of computer time, we can run tens of thousands of simulations and analyze the outputs in a probabilistic framework. We use these kinds of simulations to demonstrate the importance of residual brine saturations, the range of current options to quantify leaky well properties, and the impact of depth of injection and how it relates to leakage risk.

Integrated CO2 Pilot in France: Potential Answer to CO2 Mitigation in Bitumen Production

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 117600, "The Integrated CO2 Pilot in the SW of France (Oxy com bustion and Geological Storage): A Potential Answer to CO2 Mitigation in Bitumen Production," by Nicolas Aimard and Claude Prebende, Total, and Denis Cieutat, Ivan Sanchez-Molinero, and Remi Tsiava, Air Liquide, prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed. Development of extraheavy-oil (EHO) fields in Alberta requires much more processing and energy than for conventional oil. The amount of associated greenhouse-gas emissions could be large, and operators are seeking options to reduce them. Carbon capture and geological storage (CCGS) appears to be the most promising option in addition to power-efficiency increase and use of renewable or alternative energies. Oxycombustion could have advantages over post-combustion for CO2 capture in terms of energy efficiency for steam generation. Introduction Oil-sands-production and -processing schemes in Alberta require massive quantities of energy.Steam for use in steam-assisted gravity-drainage (SAGD) projects or for the separation of sand/bitumen extracted from miningElectricity for the water-treatment units, pumping units, separation and treatment units, and other usesHeat for treating and upgrading the produced bitumen (in particular the steam/methane reformer for hydrogen production) To produce these utilities, natural gas is burned, and thermal equipment (i.e., boilers, gas turbines, and furnaces) will generate large quantities of CO2 in the exhaust. To compare this bitumen production with other oil extraction, the ratio of the quantity of CO2 generated per barrel of produced bitumen (extraction and upgrading) is used. To produce synthetic crude oil, acceptable by conventional refineries, eight times more CO2 would be emitted through production mining (or 12 times more through SAGD) than for the extraction of conventional oil. The objective is to design facilities with the highest-possible energy efficiency. Beyond that, CO2 capture/storage would reduce CO2 emissions dramatically. The facilities must be "capture ready" (i.e., designed with the ability to integrate CO2-capture equipment). Captured CO2 then would be transported under pressure by pipeline to geological storage sites. In Alberta, potential storage sites are deep saline formations, depleted reservoirs, and enhanced-oil-recovery projects in mature oil fields. In 2006, Total launched an integrated CCGS project in southwest France, near Lacq. A drum boiler was converted into an oxycombustion unit (i.e., oxygen is used for combustion rather than air to obtain a more-concentrated CO2 stream, thus facilitating its capture). The pilot plant will produce approximately 40 tonnes/h of steam for use in other facilities and will emit up to 120 000 tonnes of CO2 over a 2-year period. The CO2 stream then will be treated, compressed, and conveyed by pipeline to the depleted gas field, Rousse, 30 km away, where it will be injected into a deep carbonate reservoir, as shown in Fig. 1.

Harmonizing the quantification of CCS GHG emission reductions through oil and natural gas industry project guidelines

Abstract The technological option of capturing CO 2 from large point sources, compressing, transporting, and injecting it for long -term storage holds the potential for playing a key role in reducing greenhouse gas (GHG) emissions while providing affordable energy. The oil and natur al gas industry experience and expertise provide confidence in carbon capture and geological storage (CCS) as an effective GHG emission mitigation option. However, companies need consistent, reliable, and credible methodologies to derive GHG emission and emission reduction estimates. Harmonizing the quantification of GHG emission reductions, by applying common principles and criteria, supports efficient and consistent development of additional project activities. This paper provides an overview of the P etroleum Industry Guidelines for Greenhouse Gas Emission Reduction Projects (referred to as the Project Guidelines), a collaborative effort between the American Petroleum Institute (API) and the International Petroleum Industry Environmental Conservation Association (IPIECA) to develop guidelines for accounting and reporting of GHG emission reduction projects of interest to the oil and natural gas industry. Key concepts from the Project Guidelines for evaluating, quantifying, documenting, and reporting GHG emission reductions are presented with a specific focus on CCS activities. The paper draws from the Project Guidelines in add ressing the selection of appropriate baseline candidates, boundaries for scenario assessment, and compatible monitoring considerations. Case studies are used to demonstrate the application of commonly accepted emission reduction principles for CCS projects. Through the Project Guidelines, API and IPIECA aim to assist the petroleum industry in identifying, assessing, and developi ng CCS projects. By working toward consistent standards for GHG emissions reductions, our industry demonstrates its commitments toward environmental improvements and p romotes the development of real and sustainable actions to reduce GHG emissions.