Pipeline Fracture Control Concepts for Norwegian Offshore Carbon Capture and Storage

2020 ◽  
Author(s):  
Gaute Gruben ◽  
Kenneth Macdonald ◽  
Svend T. Munkejord ◽  
Hans L. Skarsvåg ◽  
Stephane Dumoulin
Keyword(s):  
Carbon Capture ◽  
Shear Fracture ◽  
Saturation Pressure ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Pipe Material ◽  
Load Pressure ◽  
Offshore Pipeline ◽  
Fracture Control ◽  
Propagating Shear

Abstract The Northern Lights onshore terminal will initially receive CO2 transported by ship tankers from industrial source sites located in south-eastern Norway and transport CO2 via a 12 ¾” OD offshore pipeline for injection into the Johansen storage reservoir, located south of the Troll field. The CO2 injection pipeline will be laid from the shore terminal to a subsea wellhead structure from where the liquid CO2 will be injected into the reservoir. Presently, demonstrating arrest of longitudinal propagating shear fracture in CO2 transport pipelines is specifically addressed in two international guidelines, ISO 27913 and DNVGL-RP-F104. The study reported here aims to develop a robust fracture control methodology unique to the Northern Lights pipeline. To this end, the maximum loading in terms of saturation pressure is conservatively estimated from temperature and pressure scenarios from the planned pipeline route and applied in numerical simulations of the running-fracture phenomenon using the SINTEF coupled FE-CFD code. It is shown that, with the given pipe material, diameter, and loading conditions, the proposed wall thickness of 15.9 mm is sufficient to arrest a propagating crack. Furthermore, the Battelle TCM with ISO 27913 or DNVGL-RP-F104 arrest- and load pressure correction is shown to provide a good first estimate in pipe design, although the arrest pressure saturates for low Charpy energy toughness values, indicating limited accuracy in this study.

scholarly journals Chemistry of Reservoir Fluids in the Aspect of CO2 Injection for Selected Oil Reservoirs in Poland

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6456
Author(s):  
Ewa Knapik ◽  
Katarzyna Chruszcz-Lipska
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Oil Composition ◽  
Co2 Solubility ◽  
Geological Co2 Storage ◽  
Reservoir Conditions

Worldwide experiences related to geological CO2 storage show that the process of the injection of carbon dioxide into depleted oil reservoirs (CCS-EOR, Carbon Capture and Storage—Enhanced Oil Recovery) is highly profitable. The injection of CO2 will allow an increasing recovery factor (thus increasing CCS process profitability) and revitalize mature reservoirs, which may lead to oil spills due to pressure buildups. In Poland, such a solution has not yet been implemented in the industry. This work provides additional data for analysis of the possibility of the CCS-EOR method’s implementation for three potential clusters of Polish oil reservoirs located at a short distance one from another. The aim of the work was to examine the properties of reservoir fluids for these selected oil reservoirs in order to assure a better understanding of the physicochemical phenomena that accompany the gas injection process. The chemical composition of oils was determined by gas chromatography. All tested oils represent a medium black oil type with the density ranging from 795 to 843 g/L and the viscosity at 313 K, varying from 1.95 to 5.04 mm/s. The content of heavier components C25+ is up to 17 wt. %. CO2–oil MMP (Minimum Miscibility Pressure) was calculated in a CHEMCAD simulator using the Soave–Redlich–Kwong equation of state (SRK EoS). The oil composition was defined as a mixture of n-alkanes. Relatively low MMP values (ca. 8.3 MPa for all tested oils at 313 K) indicate a high potential of the EOR method, and make this geological CO2 storage form more attractive to the industry. For reservoir brines, the content of the main ions was experimentally measured and CO2 solubility under reservoir conditions was calculated. The reservoir brines showed a significant variation in properties with total dissolved solids contents varying from 17.5 to 378 g/L. CO2 solubility in brines depends on reservoir conditions and brine chemistry. The highest calculated CO2 solubility is 1.79 mol/kg, which suggest possible CO2 storage in aquifers.

scholarly journals Groundwater Anomaly Related to CCS-CO2 Injection and the 2018 Hokkaido Eastern Iburi Earthquake in Japan

2020 ◽  
Vol 8 ◽  
Author(s):  
Yuji Sano ◽  
Takanori Kagoshima ◽  
Naoto Takahata ◽  
Kotaro Shirai ◽  
Jin-Oh Park ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Dissolved Inorganic Carbon ◽  
Isotope Composition ◽  
Source Region ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Focal Region ◽  
Injection Point ◽  
Anthropogenic Carbon ◽  
And Storage

Carbon capture and storage (CCS) is considered a key technology for reducing CO2 emissions into the atmosphere. Nonetheless, there are concerns that if injected CO2 migrates in the crust, it may trigger slip of pre-existing faults. In order to test if this is the case, covariations of carbon, hydrogen, and oxygen isotopes of groundwater measured from Uenae well, southern Hokkaido, Japan are reported. This well is located 13 km away from the injection point of the Tomakomai CCS project and 21 km from the epicenter of September 6th, 2018 Hokkaido Eastern Iburi earthquake (M 6.7). Carbon isotope composition was constant from June 2015 to February 2018, and decreased significantly from April 2018 to November 2019, while total dissolved inorganic carbon (TDIC) content showed a corresponding increase. A decrease in radiocarbon and δ13C values suggests aquifer contamination by anthropogenic carbon, which could possibly be attributable to CCS-injected CO2. If such is the case, the CO2 enriched fluid may have initially migrated through permeable channels, blocking the fluid flow from the source region, increasing pore pressure in the focal region and triggering the natural earthquake where the brittle crust is already critically stressed.

scholarly journals Beyond Carbon Steel: Detecting Wellbore Shape and Cavities, and Cement Imperfections in Cased Wells

Energies ◽  
2019 ◽  
Vol 12 (21) ◽  
pp. 4211
Author(s):  
Timofey Eltsov ◽  
Tadeusz W. Patzek
Keyword(s):  
Magnetic Field ◽  
Carbon Steel ◽  
Oil Recovery ◽  
Magnetic Permeability ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Carbon Capture And Storage ◽  
Vertical Component ◽  
Co2 Injection ◽  
Gas Field

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.

COMMERCIAL AND TECHNICAL ISSUES FOR LARGE-SCALE CARBON CAPTURE AND STORAGE PROJECTS—A GIPPSLAND BASIN STUDY

2006 ◽  
Vol 46 (1) ◽  
pp. 435
Author(s):  
B. Hooper ◽  
B. Koppe ◽  
L. Murray
Keyword(s):  
Co2 Emissions ◽  
Brown Coal ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Carbon Capture And Storage ◽  
Gas Production ◽  
Co2 Injection ◽  
Oil And Gas Production ◽  
Gippsland Basin ◽  
And Storage

The Latrobe Valley in Victoria’s Gippsland Basin is the location of one of Australia’s most important energy resources—extremely thick, shallow brown coal seams constituting total useable reserves of more than 50,000 million tonnes. Brown coal has a higher moisture content than black coal and generates more CO2 emissions per unit of useful energy when combusted. Consequently, while the Latrobe Valley’s power stations provide Australia’s lowest- cost bulk electricity, they are also responsible for over 60 million tonnes of CO2 emissions per year—over half of the Victorian total. In an increasingly carbon constrained world the ongoing development of the Latrobe Valley brown coal resource is likely to require a drastic reduction in the CO2 emissions from new coal use projects—and carbon capture and storage (CCS) has the potential to meet such deep cuts. The offshore Gippsland Basin, the site of major producing oil and gas fields, has the essential geological characteristics to provide a high-volume, low-cost site for CCS. The importance of this potential to assist the continuing use of the nation’s lowest-cost energy source prompted the Australian Government to fund the Latrobe Valley CO2 Storage Assessment (LVCSA).The LVCSA proposal was initiated by Monash Energy (formerly APEL, and now a 100% subsidiary of Anglo American)—the proponent of a major brown coal-to-liquids plant in the Latrobe Valley. Monash Energy’s plans for the 60,000 BBL per day plant include CCS to store about 13 million tonnes of CO2 per year. The LVCSA, undertaken for Monash Energy by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), provides a medium to high-level technical and economic characterisation of the volume and cost potential for secure geosequestration of CO2 produced by the use of Latrobe Valley brown coal (Hooper et al, 2005a). The assessment’s scope includes consideration of the interaction between CO2 injection and oil and gas production, and its findings have been publicly released for use by CCS proponents, oil and gas producers and all other interested parties as an executive summary, (Hooper et al, 2005b), a fact sheet (Hooper et al, 2005c) and a presentation (Hooper et al, 2005d)).The LVCSA identifies the key issues and challenges for implementing CCS in the Latrobe Valley and provides a reference framework for the engagement of stakeholders. In effect the LVCSA constitutes a pre-feasibility study for the implementation of geosequestration in support of the continuing development of Victoria’s brown coal resources.The LVCSA findings indicate that the Gippsland Basin has sufficient capacity to safely and securely store large volumes of CO2 and may provide a viable means of substantially reducing greenhouse gas emissions from coal-fired power plants and other projects using brown coal in the Latrobe Valley. The assessment also indicates that CO2 injection could well be designed to avoid any adverse impact on adjacent oil and gas production, so that CO2 injection can begin near fields that have not yet come to the end of their productive lives. However, CCS proposals involving adjacent injection and production will require more detailed risk management strategies and continuing cooperation between prospective injectors and existing producers.

scholarly journals Assessing Potential Thermo-Mechanical Impacts on Caprock Due to CO2 Injection—A Case Study from Northern Lights CCS

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 5054
Author(s):  
Nicholas Thompson ◽  
Jamie Stuart Andrews ◽  
Tore Ingvald Bjørnarå
Keyword(s):  
Effective Stress ◽  
Carbon Capture ◽  
Storage System ◽  
Carbon Capture And Storage ◽  
Development Planning ◽  
Co2 Injection ◽  
Field Development ◽  
Stress Changes ◽  
Pressure Changes ◽  
And Storage

Due to significant temperature differences between the injected medium and in situ formation, injection of CO2 (as with water or other cold fluids) at depth induces thermal changes that must be accounted for a complete understanding of the mechanical integrity of the injection/storage system. Based on evaluations for the Northern Lights Carbon Capture and Storage (CCS) project, we focus on thermal effects induced on the caprock via conduction from cooling in the storage sands below. We investigate, using both analytical and numerical approaches, how undrained effects within the low permeability caprock can lead to volumetric contraction differences between the rock framework and the pore fluid which induce both stress and pore pressure changes that must be properly quantified. We show that such undrained effects, while inducing a more complicated response in the stress changes in the caprock, do not necessarily lead to unfavourable tensile conditions, and may, in fact, lead to increases in effective stress. These observations build confidence in the integrity of the caprock/seal system. We also show, through conservative assumptions, that pressure communication between the caprock and storage sands may lead to a localised negative effective stress condition, challenging stability of the base caprock, which will be mitigated for in field development planning.

Tracer Design and Gas Monitoring of a CO2 Injection Experiment at the ECCSEL CO2 Field Lab, Svelvik, Norway

2020 ◽  
Author(s):  
Ulrich Wolfgang Weber ◽  
Katja Heeschen ◽  
Martin Zimmer ◽  
Martin Raphaug ◽  
Klaus Hagby ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Noble Gas ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Flux Chamber ◽  
Sampling System ◽  
Injection Wells ◽  
Chemical Monitoring ◽  
Set Up ◽  
Injection Experiment

&lt;p&gt;The ECCSEL Svelvik CO&lt;sub&gt;2&lt;/sub&gt; Field Lab outside Oslo has been set up for water and CO&lt;sub&gt;2&lt;/sub&gt; injection experiments. At the site, ongoing and future investigations on monitoring techniques for carbon capture and storage (CCS) shall support the development of CCS as a climate change mitigation technology in Norway.&lt;/p&gt;&lt;p&gt;In 2019, four 100 m deep injection wells with a sophisticated physical monitoring setup were established. For chemical monitoring a fluid sampling system at injection depth was installed and coupled to a continuously measuring mass spectrometer for observing CO&lt;sub&gt;2&lt;/sub&gt; distribution. Alongside, a network of soil gas flux chambers (LI-COR 8100) were set up to monitor possible surface leakages.&lt;/p&gt;&lt;p&gt;The field lab is placed in a sand quarry within the Svelvik Ridge consisting of Holocene, siliciclastic sediments. Injection is conducted into a saltwater aquifer at 65m, supposedly sealed by clay strata. We sampled the upper fresh water aquifer at 6.5m depth and the storage aquifer at 64 - 65 m depth on dissolved gases before injection in order to design a noble gas tracer for the CO&lt;sub&gt;2&lt;/sub&gt; injection experiment. Elevated helium concentrations in the saline aquifer indicate natural radiogenic accumulation; meanwhile krypton concentrations were not naturally increased.&lt;/p&gt;&lt;p&gt;During an injection experiment in fall 2019, we added noble gases, i.e. krypton and helium, in two subsequent injection cycles, three days and one week, respectively. Outgassing was observed and high helium concentrations verified a leakage at the injection well, which we quantified with a flux chamber.&lt;/p&gt;

An Innovative Approach for Simulating CO2 Injection in Reservoir Models

2021 ◽  
Author(s):  
Gianluca Scutiero ◽  
Roberto Rossi ◽  
Guglielmo Luigi Daniele Facchi
Keyword(s):  
Carbon Capture ◽  
Oil And Gas ◽  
Regional Scale ◽  
Carbon Capture And Storage ◽  
Industrial Process ◽  
Coupling Model ◽  
Co2 Injection ◽  
Primary Input ◽  
Injection Strategy ◽  
Reservoir Models

Abstract Decarbonization is playing a major role in the near-future strategies of all the major oil and gas companies and one of most promising activity is the Carbon Capture and Storage (CCS). CCS consists in capturing CO2 coming from an industrial process and storing it in subsurface. In this project, three depleted reservoirs have been identified to inject CO2. Despite being located very close to each other, the three reservoirs are not in communication and the same surface facilities would be used for injection. The objective is to develop a suitable workflow for reservoir simulation to evaluate different injection scenarios. For this project, two wet gas reservoir and a light oil reservoir have been considered. A unique fluid description is not practical given the peculiarities of these reservoirs, as well as the construction of a single reservoir model. Currently there are some limitations in commercial solution to handle reservoirs coupling with different fluid description. A workflow has been developed using a controller that manages modules for simulating the whole asset. Injection rate of each well is calculated based on well condition and injection strategy. This process is performed for all the timestep of forecast. This solution guarantees to simulate the CO2 injection in three reservoirs in parallel in a reasonable simulation time (less than 2 hours), demonstrating the capability of overcoming the limitation of a commercial reservoir simulator related to the coupling of fields with different fluid properties. Different scenarios have been simulated considering alternative amount of CO2 to be injected. The gas injection scenario is fully accommodated inside the three reservoirs for all simulated scenarios. Moreover, the injection strategy is based on homogeneous re-pressurization of the three reservoirs and minimization of a possible well unbalancing. To achieve this objective, optimal weights to each field can be assigned to allocate the injection rates. The output of this simulation acts as primary input for dedicated studies (Cap Rock integrity, Thermally Induced Fracturing, Flow Assurance…) with the main advantage of being fully integrated at regional scale. The workflow applied in this project go beyond the main limitations of a standard reservoir coupling model. In particular, 3D reservoir models with different fluid description based on different equation of states, cannot be coupled using the standard workflows of the reservoir simulators, and anyway the available solutions are not fast and easy to implement. This approach provides a robust and flexible evaluation of the CO2 injection scenario in multiple reservoirs.

scholarly journals Soil-Gas Concentrations and Flux Monitoring at the Lacq-Rousse CO2-Geological Storage Pilot Site (French Pyrenean Foreland): From Pre-Injection to Post-Injection

2019 ◽  
Vol 9 (4) ◽  
pp. 645 ◽  
Author(s):  
Frédérick Gal ◽  
Zbigniew Pokryszka ◽  
Nadège Labat ◽  
Karine Michel ◽  
Stéphane Lafortune ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Co2 Flux ◽  
Mean Value ◽  
Soil Gas ◽  
Co2 Injection ◽  
Post Injection ◽  
Pilot Site ◽  
Gas Field ◽  
Near Surface

Soil-gas concentrations and flux were measured during 20 separate measurement campaigns at the TOTAL Lacq-Rousse carbon capture and storage (CCS) pilot site, southern France, where 51,000 tons of CO2 were injected in a depleted natural gas field. Baseline data (September 2008 to December 2009) are compared to monitoring data from the injection (March 2010 to March 2013) and post-injection (February 2014 to December 2015) periods. CO2 soil-gas concentrations varied from atmospheric concentrations to more than 16% vol. with 1.4% as median value. Summer data showed high CO2 concentrations in the soil that remained quite high during winter. Median CO2 flux at the soil/atmosphere interface was close to 4.4 cm3·min−1·m−2. Carbon-isotope ratios measured on CO2 in soil gas had a mean value of −23.5 ± 3.1‰, some deviation being due to atmospheric CO2. Comparison between different gas species and the influence of temperature, pressure and soil-water content suggest that gases in near-surface environments are produced locally and naturally, and are unrelated to CO2 ascending from the storage reservoir. Monitoring of CO2 injection and the use of threshold levels is discussed as part of a practical approach considering specific regulations for the Lacq-Rousse CCS pilot experiment and constraints for the site operator.

scholarly journals Periodic CO2 Injection for Improved Storage Capacity and Pressure Management under Intermittent CO2 Supply

Energies ◽  
2022 ◽  
Vol 15 (2) ◽  
pp. 566
Author(s):  
Anton Shchipanov ◽  
Lars Kollbotn ◽  
Mauro Encinas ◽  
Ingebret Fjelde ◽  
Roman Berenblyum
Keyword(s):  
Feasibility Study ◽  
Carbon Capture ◽  
Storage Capacity ◽  
Carbon Capture And Storage ◽  
Geological Structure ◽  
Co2 Injection ◽  
Storage Site ◽  
Pressure Management ◽  
Field Scale ◽  
And Storage

Storing CO2 in geological formations is an important component of reducing greenhouse gases emissions. The Carbon Capture and Storage (CCS) industry is now in its establishing phase, and if successful, massive storage volumes would be needed. It will hence be important to utilize each storage site to its maximum, without challenging the formation integrity. For different reasons, supply of CO2 to the injection sites may be periodical or unstable, often considered as a risk element reducing the overall efficiency and economics of CCS projects. In this paper we present outcomes of investigations focusing on a variety of positive aspects of periodic CO2 injection, including pressure management and storage capacity, also highlighting reservoir monitoring opportunities. A feasibility study of periodic injection into an infinite saline aquifer using a mechanistic reservoir model has indicated significant improvement in storage capacity compared to continuous injection. The reservoir pressure and CO2 plume behavior were further studied revealing a ‘CO2 expansion squeeze’ effect that governs the improved storage capacity observed in the feasibility study. Finally, the improved pressure measurement and storage capacity by periodic injection was confirmed by field-scale simulations based on a real geological set-up. The field-scale simulations have confirmed that ‘CO2 expansion squeeze’ governs the positive effect, which is also influenced by well location in the geological structure and aquifer size, while CO2 dissolution in water showed minor influence. Additional reservoir effects and risks not covered in this paper are then highlighted as a scope for further studies. The value of the periodic injection with intermittent CO2 supply is finally discussed in the context of deployment and integration of this technology in the establishing CCS industry.

scholarly journals Why CCS? Milestone on Research and Regulation Coverages

KnE Energy ◽  
2015 ◽  
Vol 1 (1) ◽  
pp. 13
Author(s):  
Aisyah Kusuma ◽  
Eko Widianto ◽  
Rachmat Sule ◽  
Wawan Gunawan A. Kadir ◽  
Mega S. Gemilang
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Emission ◽  
Fossil Fuels ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Point Sources ◽  
Co2 Injection ◽  
Road Map ◽  
And Storage

<p>Further to Kyoto Protocol, again in 2009 G-20 Pittsburg Summit, Indonesia delivered the commitment on reducing 26% on its emission level. Moreover, as non-annex 1 country, Indonesia shows strong and bold commitment in supporting reduction on increased concentrations of greenhouse gases produced by human activities such as burning the fossil fuels and deforestation. From the energy sector, Carbon Capture and Storage (CCS) is known as a process of capturing waste carbon dioxide (CO2) from large point sources and depositing it normally at an underground geological formation. CCS becomes now as one of the possible supports to the country commitment. In Indonesia, the potential of CCS applications could be conducted in the gas fields with high content of CO2 and in almost depleted oil fields (by applying CO2-Enchanced Oil Recovery (EOR) The CCS approach could also be conducted in order to increase hydrocarbon production, and at the same time the produced CO2 will be injected and storage it back to the earth. Thus, CCS is a mitigation process in enhancing carbon emission reduction caused by green house effect from production hydrocarbon fields.</p><p>This paper will show a proposed milestone on CCS Research roadmap, as steps to be taken in reaching the objective. The milestone consists of the study for identifying potential CO2 sources, evaluating CO2 storage sites, detail study related to CO2 storage selection, CO2 injection, and CO2 injection monitoring. Through these five steps, one can expect to be able to comprehend road map of CCS Research. Through this research milestone, applications of CCS should also be conducted based on the regulatory coverage milestone. From this paper, it is hoped that one can understand the upstream activities starting with research milestone to the very end downstream activities regarding to the regulation coverage bound. </p><p><em><strong>Keywords</strong></em>: CCS, reduction of carbon emission, regulation umbrella </p>

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