CO2 sequestration, also known as CO2 capture and storage (CCS), uses a range of technologies and approaches that isolate, extract, and store carbon dioxide emissions from industrial and energy-related sources in order to prevent the release of it into the atmosphere. Carbon capture and storage technology involves the process of trapping and separating the CO2, transporting it to a storage location, and then storing it long-term so that it does not enter into the atmosphere. It is not a new technology and has been used by petroleum, chemical, and power industries for decades. In fact, carbon capture was first used in Texas in 1972 as a method to enhance oil recovery. CO2 emissions from the burning of fossil fuels has been on the incline since the industrial era; and with more than 85% of the world's energy coming from fossil fuels, it will remain an important energy source well into the future. As the demand for fossil fuels is growing, so is the volume of CO2 emitted each year.
Boersheim, Erik Clemens (Clausthal University of Technology) | Reitenbach, Victor (Clausthal University of Technology) | Albrecht, Daniel (Clausthal University of Technology) | Pudlo, Dieter (FSU Jena) | Ganzer, Leonhard (Clausthal University of Technology)
Hydrogen is portrayed as the fuel of the future. The storage of hydrogen in porous underground gas storages is a promising solution for large-scale energy storage in Germany. In theory, excess energy sourced from renewable sources would be converted to hydrogen and subsequently stored in underground porous media. This solution provides cost effective solutions whilst providing large capacities in comparison to other energy storage types, however hydrogen interactions in underground gas storage sites (UGS) is a perplexing topic due to its foreign nature and therefore its behavior in the subsurface could be unpredictable.
The implementation of autoclaves to recreate UGS with added hydrogen is a novel approach to investigate potential integrity issues that may arise during its lifetime. Where autoclaves can simulate conditions similar to UGS to analyze potential changes in the subsurface. The principal idea of autoclaves are to house samples which are exposed to pressures and temperatures equivalent that of typical Underground Gas Storages (max 200 bar, 120°C), allowing the recreation of any reservoir environment.
The Primary objective is to investigate interactions between subsurface materials combined with reservoir rock and hydrogen. Aforementioned interactions can be interpreted through the analysis of mineralogical, petrophysical, hydrochemical changes to ascertain information regarding to the productivity of the UGS, for examples reviewing changes in permeability and porosity.
Furthermore, the application of autoclaves can help to estimate the magnitude of hydrogen damage in subsurface equipment by providing insight into identifying key materials necessary to design a system preventing hydrogen damage to the subsurface; Supplementary implementation of conventional component inspection of mechanical properties of steels and cements through tensile strength testing and unconfined compressive strength testing, respectively, enable the extent of hydrogen damage inspection in UGS with added hydrogen. Predominantly API grade steels and API Grade G cement where used for this investigation. Preliminary autoclave experimentation results show that hydrogen can alter the characteristics of UGS, where API steels have shown to experience mild hydrogen damage and reservoir rock and API cement G samples have alterations in their chemical and physical characteristics.
Autoclaves provide flexible choice in testing parameters and can be used to recreate any UGS with any gas mixtures, allowing for limitless testing possibilities to test for potential integrity issues in porous UGS containing hydrogen.
CCUS is an interdisciplinary research field and its broad scope means that CCUS offers numerous opportunities for science and engineering graduates, including petroleum engineers. Underbalanced coiled tubing drilling has continually advanced since the first trials in the 1990s but remains a relatively niche drilling technology. With UBCTD projects set to start in many countries next year, this technology may be seeing a turning point.
Briefly stated, carbon capture and sequestration (CCS) will help us to sustain many of the benefits of using hydrocarbons to generate energy as we move into a carbon-constrained world. Even though the CO2 generated by burning hydrocarbons cannot always be captured easily in some cases (as in oil used for transportation), sequestration of CO2 from other sources (such as coal-fired power stations) can help to create, to some degree, the “headroom” needed for the volumes of CO2 that escape capture. Because of the likely continuing competitive (direct) cost of hydrocarbons and in light of the huge investment in infrastructure already made to deliver them, the combination of fossil fuel use with CCS is likely to be emphasized as a strong complement to strategies involving alternative, nonhydrocarbon sources of energy. Moreover, the exploitation of heavy oil, tar sands, oil shales, and liquids derived from coal for transportation fuel is likely to increase, even though these come with a significantly heavier burden of CO2 than that associated with conventional oil and gas. CCS has the potential to mitigate some of this extra CO2 burden. If we wish to sustain the use of oil, gas, and coal to meet energy demands in a carbon-constrained world and to provide time to move toward alternative energy sources, then it will be necessary to plan for and implement CCS over the coming decades. Subsequently, we should expect a continued need for CCS beyond the end of the century.
A new integrated modeling tool helps Canada analyze methane emissions to get a better understanding of the economic and environmental implications. While much progress has been made to reduce flaring, associated gas continues to be flared at thousands of oil production sites around the world. The Pipeline and Hazardous Materials Safety Administration has announced an additional comment period on its 19 December 2016 interim final rule that established minimum federal safety standards for underground natural gas storage facilities.
Ding, Shuaiwei (National & Local Joint Engineering Research Center for Carbon Capture and Sequestration Technology, State Key Laboratory for Continental Dynamics, Northwest University) | Liu, Guangwei (CNOOC Research Institute) | Li, Peng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields) | Xi, Yi (Exploration and Development Research Institute, Petro-China Changqing Oil Field Company Ltd) | Ma, Jinfeng (National Engineering Laboratory for Exploration and Development of Low-Permeability Oil & Gas Fields)
Oil reservoirs are considered good storage structures for CO2 geological storage. With the right selection of candidate reservoir, injection of CO2 into tertiary and depleted oil reservoirs can result in enhanced oil recovery (EOR) and permanent sequestration of CO2 underground. The selection of candidate reservoirs for future CO2-EOR and storage projects mainly depends on storage potential evaluation. The aim of this work is to estimate the storage potential of CO2 stored in tertiary (CO2-EOR) and depleted oil reservoirs. In tertiary oil reservoirs, a method to estimate the geological CO2 storage capacity (CO2SC) in the reservoir during well open operations (EOR operations), which is a function of reservoir parameters, original geological reserves and oil volume factor is first built. In depleted oil reservoirs, a method to calculate the CO2SC in the reservoir during well shut down operations, which is based on the material balance method is proposed. In both cases, the methodology of storage capacity of CO2 dissolved in remaining oil, formation water and by mineral trapping is presented based on the model established by
Tavassoli, Shayan (The University of Texas at Austin) | Shafiei, Mohammadreza (The University of Texas at Austin) | Minnig, Christian (swisstopo) | Gisiger, Jocelyn (Solexperts) | Rösli, Ursula (Solexperts) | Patterson, James (ETHZ) | Theurillat, Thierry (swisstopo) | Mejia, Lucas (The University of Texas at Austin) | Goodman, Harvey (Chevron ETC) | Espie, Tony (BP) | Balhoff, Matthew (The University of Texas at Austin)
Wellbore integrity is a critical subject in oil and gas production, and CO2 storage. Successful subsurface deposition of various fluids, such as CO2, depends on the integrity of the storage site. In a storage site, injection wells and pre-existing wells might leak due to over-pressurization, mechanical/chemical degradation, and/or a poor cement job, thus reducing the sealing capacity of the site. Wells that leak due to microannuli or cement fractures on the order of microns are difficult to seal with typical workover techniques. We tested a novel polymer gelant, originally developed for near borehole isolation, in a pilot experiment at Mont Terri, Switzerland to evaluate its performance in the aforementioned scenario.
The polymer gel sealant was injected to seal a leaky wellbore drilled in the Opalinus Clay as a pilot test. The success of the pH-triggered polymer gel (sealant) in sealing cement fractures was previously demonstrated in laboratory coreflood experiments (
The novel sealant was successfully deployed to seal the small aperture pathways of the borehole at the pilot test. We conducted performance tests using formation brine and CO2 gas to put differential pressure on the polymer gel seal. Pressure and flow rate at the specific interval were monitored during and after injection of brine and CO2. Results of performance tests after polymer injection were compared against those in the absence of the sealant.
Several short-term (4 min) constant-pressure tests at different pressure levels were performed using formation brine, and no significant injection flow rate (rates were below 0.3 ml/min) was observed. The result shows more than a ten-fold drop in the injection rate compared to the case without the sealant. The polymer gel showed compressible behavior at the beginning of the short-term performance tests. Our long-term (1-week) test shows even less injectivity (~0.15 ml/min) after polymer gelation. The CO2 performance test shows only 3 bar pressure dissipation overnight after injection compared to abrupt loss of CO2 pressure in the absence of polymer gel. Sealant shows good performance even in the presence of CO2 gas with high diffusivity and acidity.
Pilot test of our novel sealant proves its competency to mitigate wellbore leakage through fractured cement or debonded microannuli, where other remedy techniques are seldom effective. The effectiveness of the sealing process was successfully tested in the high-alkaline wellbore environment of formation brine in contact with cement. The results to date are encouraging and will be further analyzed once over-coring of the wellbore containing the cemented annulus occurs. The results are useful to understand the complexities of cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.