Maturing global CO2 storage resources on offshore continental margins to achieve 2DS emissions reductions

AbstractMost studies on CO2 emissions reduction strategies that address the ‘two-degree scenario’ (2DS) recognize a significant role for CCS. For CCS to be effective, it must be deployed globally on both existing and emerging energy systems. For nations with large-scale emissions, offshore geologic CO2 storage provides an attractive and efficient long-term strategy. While some nations are already developing CCS projects using offshore CO2 storage resources, most geographic regions have yet to begin. This paper demonstrates the geologic significance of global continental margins for providing broadly-equitable, geographically-relevant, and high-quality CO2 storage resources. We then use principles of pore-space utilization and subsurface pressure constraints together with analogs of historic industry well deployment rates to demonstrate how the required storage capacity can be developed as a function of time and technical maturity to enable the global deployment of offshore storage for facilitating 2DS. Our analysis indicates that 10–14 thousand CO2 injection wells will be needed globally by 2050 to achieve this goal.

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Landscape development in western and central Dronning Maud Land, East Antarctica

Antarctic Science ◽

10.1017/s0954102001000438 ◽

2001 ◽

Vol 13 (3) ◽

pp. 302-311 ◽

Cited By ~ 18

Author(s):

Jens-Ove Näslund

Keyword(s):

Large Scale ◽

High Elevation ◽

Continental Margins ◽

Landscape Development ◽

Ice Streams ◽

The North ◽

Ice Stream ◽

Dronning Maud Land ◽

Break Up

Large-scale bedrock morphology and relief of two key areas, the Jutulsessen Nunatak and the Jutulstraumen ice stream are used to discuss glascial history and landscape development in western and central Dronning Maud Land, Antarctica. Two main landform components were identified: well-defined summit plateau surfaces and a typical alpine glacial landscape. The flat, high-elevation plateau surfaces previously were part of one or several continuous regional planation surfaces. In western Dronning Maud Land, overlying cover rocks of late Palaeozoic age show that the planation surface(s) existed in the early Permian, prior to the break-up of Gondwana. A well-develoment escarpment, a mega landform typical for passive continental margins, bounds the palaeosurface remnants to the north for a distance of at least 700 km. The Cenozoic glacial landscape, incised in the palaeosurface and escarpment, is exemplified by Jutulsessen Nunatak, where a c. 1.2 km deep glacial valley system is developed. However, the prominent Penck-Jutul Trough represents some of the deepest dissection of the palaeosurface. This originally tectonic feature is today occupied by the Jutulstraumen ice stream. New topographic data show that the bed of the Penck-Jutul Trough is situated 1.9±1.1 km below sea level, and that the total landscape relief is at least 4.2 km. Today's relief is a result of several processes, including tectonic faulting, subaerial weathering, fluvial erosion, and glacial erosion. It is probable that erosion by ice streams has deepened the tectonic troughs of Dronning Maud Land since the onset of ice sheet glaciation in the Oligocene, and continues today. An attempt is made to identify major events in the long-term landscape development of Dronning Maud Land, since the break-up of the Gondwana continent.

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Numerical Modelling of a District Scale Groundwater Heat Pump Operation: Case Study from Colchester, UK

10.5194/egusphere-egu21-603 ◽

2021 ◽

Author(s):

Taha Sezer ◽

Abubakar Kawuwa Sani ◽

Rao Martand Singh ◽

David P. Boon

Keyword(s):

Large Scale ◽

District Level ◽

Thermal Plume ◽

Injection Wells ◽

Term Operation ◽

Heating And Cooling ◽

Groundwater Heat Pump ◽

The Impact

Groundwater heat pumps (GWHP) are an environmentally friendly and highly efficient low carbon heating technology that can benefit from low-temperature groundwater sources lying in the shallow depths to provide heating and cooling to buildings. However, the utilisation of groundwater for heating and cooling, especially in large scale (district level), can create a thermal plume around injection wells. If a plume reaches the production well this may result in a decrease in the system performance or even failure in the long-term operation. This research aims to investigate the impact of GWHP usage in district-level heating by using a numerical approach and considering a GWHP system being constructed in Colchester, UK as a case study, which will be the largest GWHP system in the UK. Transient 3D simulations have been performed pre-construction to investigate the long-term effect of injecting water at 5&#176;C, into a chalk bedrock aquifer. Modelling suggests a thermal plume develops but does not reach the production wells after 10 years of operation. The model result can be attributed to the low hydraulic gradient, assumed lack of interconnecting fractures, and large (>500m) spacing between the production and injection wells. Model validation may be possible after a period operational monitoring.

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Mapping of the CO2 storage potential in the Nordic region

Geological Survey of Denmark and Greenland Bulletin ◽

10.34194/geusb.v35.4946 ◽

1969 ◽

Vol 35 ◽

pp. 87-90

Author(s):

Karen Lyng Anthonsen ◽

Peter Frykman ◽

Carsten Møller Nielsen

Keyword(s):

Natural Gas ◽

Storage Capacity ◽

Carbon Tax ◽

Pore Space ◽

Co2 Storage ◽

Point Sources ◽

Research Projects ◽

High Co2 ◽

Nordic Region ◽

The World

The concept of utilising available pore space in deep saline sandstone aquifers for storage of CO2 was recognised in the late 1980s. In 1996, the first commercial CO2 storage project began with injection into sandstones of the Utsira Formation in Norway. The formation is located above the Sleipner Formation from where the Sleipner field produces natural gas. The project was initiated due to a high CO2 content of the natural gas, which was subjected to a Norwegian offshore carbon tax. The natural gas is produced on the Sleipner platform where the CO2 is separated, captured and reinjected from a neighbouring platform. The potential for using the technology to reduce CO2 emissions from large stationary point sources initiated many research projects aimed at mapping areas with potential CO2 storage capacity around the world.

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Integrated static modelling and dynamic simulation framework for CO2 storage capacity in upper Qishn Clastics, S1A reservoir, Yemen

10.21203/rs.3.rs-503826/v1 ◽

2021 ◽

Author(s):

Ayman Mutahar AlRassas ◽

Hung Vo Thanh ◽

Shaoran Ren ◽

Renyuan Sun ◽

Nam Le Nguyen Hai ◽

...

Keyword(s):

Oil Recovery ◽

Large Scale ◽

Storage Capacity ◽

Co2 Storage ◽

Uncertainty Assessment ◽

Alternative Measure ◽

Modeling Framework ◽

Significant Difference ◽

Static Modelling ◽

And Storage

Abstract Carbon dioxide (CO2) capture and storage (CCS) is presented as an alternative measure and promising approach to mitigate the large-scale anthropogenic CO2 emission into the atmosphere. In this context, CO2 sequestration into depleted oil reservoirs is a practical approach as it boosts the oil recovery and facilitates the permanent storing of CO2 into the candidate sites. However, the estimation of CO2 storage capacity in subsurfaces is a challenge to kick-start CCS worldwide. Thus, this paper proposes an integrated static and dynamic modeling framework to tackle the challenge of CO2 storage capacity in a clastic reservoir, S1A filed, Masila basin, Yemen. To achieve this work's ultimate goal, the geostatistical modeling was integrated with open-source code (MRST-CO2lab) for reducing the uncertainty assessment of CO2 storage capacity. Also, there is a significant difference between static and dynamic CO2 storage capacity. The static CO2 storage capacity varies from 4.54 to 81.98 million tons, while the dynamic CO2 simulation is estimated from 4.95 to 17.92 million tons. Based on the geological uncertainty assessment of three ranked realizations (P10, P50, P90), our work was found that the upper Qinshn sequence could store 15.64 Million tons without leakage. This result demonstrates that the potential of CO2 utilization is not only in this specific reservoir, but the further CO2 storage for the other clastics reservoirs is promising in the Masila Basin, Yemen.

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Investigations on the permeability of MgO concrete with 5-1-8 phase at the GV2-drift-sealing in the Teutschenthal mine

10.5194/egusphere-egu2020-12948 ◽

2020 ◽

Author(s):

Jennifer Arendt ◽

Wolfram Kudla ◽

Thomas Wilsnack ◽

Till Popp ◽

Daniela Freyer

Keyword(s):

Large Scale ◽

Gas Permeability ◽

Pore Space ◽

Binder Phase ◽

Self Healing ◽

Measuring Period ◽

Mgo Concrete ◽

Over Time ◽

Drill Cores

For underground storage facilities and future HAW repositories, a secure closure is indispensable. Within the scope of two consecutive research projects, three closure elements were installed in large-scale tests at the Teutschenthal mine in the Carnallitit Mountains between 2006 and 2008. Special mention should be made here of the large-scale test 2 (&#8220;GV2&#8221;), which was produced from MgO concrete with the 5-1-8 binder phase. This structure was made using the dry-mix shotcrete procedure. The low temperature development during the setting of the shotcrete was very advantageous. The 10.25 m long structure, with a height and width of 3.55 m each, consists of 104 concreting sections with an average layer thickness of 9.9 cm. It was of interest whether the concreting section boundaries (&#8220;BAG&#8221;) influence the permeability (negatively). The structure is equipped with pressure transmitters and TDR sensors in three measuring levels. After completion of the structure and injections in the contact area, the integral system permeability was 2*10&#8209;16 m&#178;. Liquid pressurization via pressure chamber was carried out on the test structure after a maturing period of about 10 years. After 8 years, the permeability with gas and with solution was determined in boreholes and on drill cores, especially with regard to the development over time. The determined in-situ gas permeability is on average 2.7*10&#8209;19&#160;m&#178;, on compact concrete (without BAGs) on average 2.0*10-20&#160;m&#178;. Test areas containing BAGs showed a higher permeability of maximum three orders of magnitude in some measurements. The solution permeability was determined both with a saturated NaCl solution and with a NaCl-saturated solution containing MgCl2 and is between 1.0*10&#8209;20&#160;m&#178; and 9.0*10&#8209;20&#160;m&#178;, whereby this decreases by half a power of ten over the measurement period of 600 days. In further integral injection tests in 4.5&#160;m and 4.8&#160;m long boreholes, a significant decrease in permeability over time was also observed. From an initial 2*10&#8209;15&#160;m&#178; and 4*10&#8209;16&#160;m&#178;, respectively, the integral permeability decreased to <10&#8209;19 m&#178; over a measuring period of 2.5 years. The reason for this decrease is the reduction of pore space due to the recrystallization of MgO and the transformation of the metastable 5-1-8 phase to the long-term stable 3-1-8 phase due to the increase in volume that takes place when the solution is added. Potential weak points or defects at the technically determined concrete section boundaries, therefore, do not represent weak zones in the structure in the long term due to this self-healing effect.This paper reports on the large-scale experiment GV2 made of MgO concrete with 5-1-8 phase and the comprehensive permeability and strength investigations in drillings and on drill cores. The test results are the precondition for a modeling of the long-term behaviour of MgO-concrete.

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Safeguarding CO2 Storage in a Depleted Offshore Gas Field with Adaptive Approach of Monitoring, Measurement and Verification MMV

10.2118/204590-ms ◽

2021 ◽

Cited By ~ 1

Author(s):

Pankaj Kumar Tiwari ◽

Prasanna Chidambaram ◽

Ahmad Ismail Azahree ◽

Debasis Priyadarshan Das ◽

Parimal Arjun Patil ◽

...

Keyword(s):

Co2 Sequestration ◽

Co2 Storage ◽

Storage Site ◽

Injection Wells ◽

Plume Front ◽

Plume Migration ◽

Co2 Plume ◽

4D Seismic ◽

And Storage

Abstract CO2 sequestration is a process for eternity with a possibility of zero-degree failure. One of the key components of the CO2 Sequestration Project is to have a site-specific, risk-based and adaptive Monitoring, Measurement and Verification (MMV) plan. The storage site has been studied thoroughly and is understood to be inherently safe for CO2 sequestration. However, it is incumbent on operator to manage and minimize storage risks. MMV planning is critical along with geological site selection, transportation and storage process. Geological evaluation study of the storage site suggests the containment capacity of identified large depleted gas reservoirs as well as long term conformance due to thick interval. The fault-seal analysis and reservoir integrity study contemplate long-term security of the CO2 storage. An integrated 3D reservoir dynamic simulation model coupled with geomechanical and geochemical models were performed. This helps in understanding storage capacity, trapping mechanisms, reservoir integrity, plume migration path, and injectivity. To demonstrate that CO2 plume migration can be mapped from the seismic, a 4D Seismic feasibility study was carried out using well and fluid data. Gassmann fluid substitution was performed in carbonate reservoir at well, and seismic response of several combination of fluid saturation scenarios on synthetic gathers were analyzed. The CO2 dispersion study, which incorporate integration of subsurface, geomatic and metocean & environment data along with leakage character information, was carried out to understand the potential leakage pathway along existing wells and faults which enable to design a monitoring plan accordingly. The monitoring of wells & reservoir integrity, overburden integrity will be carried out by Fiber Optic System to be installed in injection wells. Significant difference in seismic amplitude observed at the reservoir top during 4D seismic feasibility study for varying CO2 saturation suggests that monitoring of CO2 plume migration from seismic is possible. CO2 plume front with as low as 25% saturation can be discriminated provided seismic data has high signal noise ratio (SNR). 3D DAS-VSP acquisition modeling results show that a subsurface coverage of approximately 3 km2 per well is achievable. Laboratory injectivity studies and three-way coupled modelling simulations established that three injection wells will be required to achieve the target injection rate. As planned injection wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume front. Hence, surface seismic acquisition will be an integral component of full field monitoring and time-lapsed evaluations for integrated MMV planning to monitor CO2 plume migration. The integrated MMV planning is designed to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection. Field specific MMV technologies for CO2 plume migration with proactive approach were identified after exercising pre-defined screening criteria.

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Optimization Wells Placement Policy for Enhanced CO2 Storage Capacity in Mature Oil Reservoirs

Energies ◽

10.3390/en13164054 ◽

2020 ◽

Vol 13 (16) ◽

pp. 4054

Author(s):

Michał Kuk ◽

Edyta Kuk ◽

Damian Janiga ◽

Paweł Wojnarowski ◽

Jerzy Stopa

Keyword(s):

Carbon Dioxide ◽

Carbon Dioxide Emissions ◽

Storage Capacity ◽

Co2 Storage ◽

Oil Field ◽

Ecological Effect ◽

Co2 Injection ◽

Reservoir Properties ◽

Injection Wells ◽

Co2 Eor

One of the possibilities to reduce carbon dioxide emissions is the use of the CCS method, which consists of CO2 separation, transport and injection of carbon dioxide into geological structures such as depleted oil fields for its long-term storage. The combination of the advanced oil production method involving the injection of carbon dioxide into the reservoir (CO2-EOR) with its geological sequestration (CCS) is the CCS-EOR process. To achieve the best ecological effect, it is important to maximize the storage capacity for CO2 injected in the CCS phase. To achieve this state, it is necessary to maximize recovery factor of the reservoir during the CO2-EOR phase. For this purpose, it is important to choose the best location of CO2 injection wells. In this work, a new algorithm to optimize the location of carbon dioxide injection wells is developed. It is based on two key reservoir properties, i.e., porosity and permeability. The developed optimization procedure was tested on an exemplary oil field simulation model. The obtained results were compared with the option of arbitrary selection of injection well locations, which confirmed both the legitimacy of using well location optimization and the effectiveness of the developed optimization method.

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A Review on the Influence of CO2/Shale Interaction on Shale Properties: Implications of CCS in Shales

Energies ◽

10.3390/en13123200 ◽

2020 ◽

Vol 13 (12) ◽

pp. 3200

Author(s):

Ahmed Fatah ◽

Ziad Bennour ◽

Hisham Ben Mahmud ◽

Raoof Gholami ◽

Md. Mofazzal Hossain

Keyword(s):

Mechanical Properties ◽

Adsorption Capacity ◽

Shale Gas ◽

Storage Capacity ◽

Co2 Storage ◽

Co2 Injection ◽

Shale Formations ◽

Shale Formation ◽

Co2 Treatment

Carbon capture and storage (CCS) is a developed technology to minimize CO2 emissions and reduce global climate change. Currently, shale gas formations are considered as a suitable target for CO2 sequestration projects predominantly due to their wide availability. Compared to conventional geological formations including saline aquifers and coal seams, depleted shale formations provide larger storage potential due to the high adsorption capacity of CO2 compared to methane in the shale formation. However, the injected CO2 causes possible geochemical interactions with the shale formation during storage applications and CO2 enhanced shale gas recovery (ESGR) processes. The CO2/shale interaction is a key factor for the efficiency of CO2 storage in shale formations, as it can significantly alter the shale properties. The formation of carbonic acid from CO2 dissolution is the main cause for the alterations in the physical, chemical and mechanical properties of the shale, which in return affects the storage capacity, pore properties, and fluid transport. Therefore, in this paper, the effect of CO2 exposure on shale properties is comprehensively reviewed, to gain an in-depth understanding of the impact of CO2/shale interaction on shale properties. This paper reviews the current knowledge of the CO2/shale interactions and describes the results achieved to date. The pore structure is one of the most affected properties by CO2/shale interactions; several scholars indicated that the differences in mineral composition for shales would result in wide variations in pore structure system. A noticeable reduction in specific surface area of shales was observed after CO2 treatment, which in the long-term could decrease CO2 adsorption capacity, affecting the CO2 storage efficiency. Other factors including shale sedimentary, pressure and temperature can also alter the pore system and decrease the shale “caprock” seal efficiency. Similarly, the alteration in shales’ surface chemistry and functional species after CO2 treatment may increase the adsorption capacity of CO2, impacting the overall storage potential in shales. Furthermore, the injection of CO2 into shales may also influence the wetting behavior. Surface wettability is mainly affected by the presented minerals in shale, and less affected by brine salinity, temperature, organic content, and thermal maturity. Mainly, shales have strong water-wetting behavior in the presence of hydrocarbons, however, the alteration in shale’s wettability towards CO2-wet will significantly minimize CO2 storage capacities, and affect the sealing efficiency of caprock. The CO2/shale interactions were also found to cause noticeable degradation in shales’ mechanical properties. CO2 injection can weaken shale, decrease its brittleness and increases its plasticity and toughness. Various reductions in tri-axial compressive strength, tensile strength, and the elastic modulus of shales were observed after CO2 injection, due to the dissolution effect and adsorption strain within the pores. Based on this review, we conclude that CO2/shale interaction is a significant factor for the efficiency of CCS. However, due to the heterogeneity of shales, further studies are needed to include various shale formations and identify how different shales’ mineralogy could affect the CO2 storage capacity in the long-term.

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Managing clastic reservoir heterogeneity II: Geological modelling and reservoir characterisation of the Minjur Sandstone at the Khashm al Khalta type locality (Central Saudi Arabia)

GeoArabia ◽

10.2113/geoarabia170361 ◽

2012 ◽

Vol 17 (3) ◽

pp. 61-80 ◽

Cited By ~ 1

Author(s):

Benoît Issautier ◽

Yves-Michel Le Nindre ◽

Sophie Viseur ◽

Abdullah Memesh ◽

Saleh Dini

Keyword(s):

Saudi Arabia ◽

Spatial Distribution ◽

Large Scale ◽

Storage Capacity ◽

International System ◽

Co2 Storage ◽

Depositional Environments ◽

Type Locality ◽

Reservoir Heterogeneity ◽

Sandstone Reservoir

ABSTRACT The increasing demand on geological reservoirs, whether for developing geothermal energy or for CO2 geological storage, raises questions on how reservoir heterogeneity might increase or decrease reservoir performance. To address this issue we selected the Minjur Sandstone Formation, a groundwater-bearing formation of Triassic age in Central Saudi Arabia, for complex reservoir modelling, simulation and prediction of the spatial distribution of sand bodies in a fluvio-deltaic system. This paper builds on a previous study that focused on the facies, stratigraphy, and reservoir characterisation of the Minjur Sandstone at the Khashm al Khalta type locality. Its purpose is to construct a deterministic 3-D model for (1) studying the connectivity of the Minjur Sandstone, and (2) illustrating a typical fluvio-deltaic reservoir and its associated heterogeneity. A first model simulates the spatial distribution of the depositional environments, which were further coded into relative proportions of sand, shale, evaporites and carbonates. This leads to a second model that contributes to reservoir applications through estimating the reservoir’s volume and storage capacities. Sequences 1 to 4 of the succession (Upper Jilh Formation–Lower Minjur Member), with a net-to-gross sand/shale ratio (NG) of ca. 8%, consist of poorly connected sandstone reservoir bodies. In contrast, sequences 5 to 9 (Upper Minjur Member), with an average NG of ca. 42%, consist of well-interconnected sandstone reservoir bodies. The NG depends on the tectonic influence and on relative sea-level variations. The best Minjur Sandstone reservoir bodies are at the base of each sequence, where limited available space favours a stack of deposits: interconnected fluvial channels which form wide spreads of coarse sandstone showing little diagenesis. The greatest potential is in the Upper Minjur Member. The effective reservoir volume was isolated using a sand content of > 85%. Rock volume and pore volume for an average porosity of 17% were subsequently calculated from the outcrop model. A representative block of 600 m x 600 m x 144 m was selected in order to simulate a fraction of the reservoir with the same properties as the whole. The block’s CO2 storage capacity was 57,000 tonne (in the International System, ‘SI’) for an arbitrary CO2 density of 0.7 (supercritical). This result was then transposed to the aquifer in the Riyadh area where similar conditions are assumed to exist. To obtain a ‘reservoir scale’ estimation, the block dimensions were upscaled to 20 km x 20 km x 80 m (the last figure being the effective thickness given by hydrogeological studies). The inferred storage capacity here was 30.5 Mt (million tonnes, International unit System, ‘SI’), which is an excellent figure when one considers the large-scale projects of Europe (Sleipner: 20 Mt) and Canada (Weyburn: 14 Mt).

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Quantifying Uncertainty through 3D Geological Modeling for Carbon Capture Utilization and Storage in the Unayzah Formation in Saudi Arabia

10.5194/egusphere-egu21-12839 ◽

2021 ◽

Author(s):

Sofia Mantilla Salas ◽

Miguel Corrales ◽

Hussein Hoteit ◽

Abdulkader Alafifi ◽

Alexandros Tasianas

Keyword(s):

Saudi Arabia ◽

Carbon Capture ◽

Large Scale ◽

Storage Capacity ◽

Co2 Storage ◽

High Energy ◽

Sequential Gaussian Simulation ◽

Storage Site ◽

The Impact ◽

And Storage

The development of Carbon Capture Utilization and Storage (CCUS) technology paired with existing energy systems will facilitate a successful transition to a carbon-neutral economy that offers efficient and sustainable energy. It will also enable the survival of multiple and vital economic sectors of high-energy industries that possess few other options to decarbonize. Nowadays, just about one-ten-thousandth of the global annual emissions are being captured and geologically-stored, and therefore with today&#8217;s emission panorama, CCS large-scale deployment is more pressing than ever. In this study, a 3D model that represents the key reservoir uncertainties for a CCUS pilot was constructed to investigate the feasibility of CO2 storage in the Unayzah Formation in Saudi Arabia. The study site covers the area of the city of Riyadh and the Hawtah and Nuayyim Trends, which contain one of the most prolific petroleum-producing systems in the country. The Unayzah reservoir is highly stratified and it is subdivided into three compartments: the Unayzah C (Ghazal Member), the Unayzah B (Jawb Member), and the Unayzah A (Wudayhi and Tinat Members). This formation was deposited under a variety of environments, such as glaciofluvial, fluvial, eolian, and coastal plain. Facies probability trend maps and well log data were used to generate a facies model that accounted for the architecture, facies distribution, and lateral and vertical heterogeneity of this high complexity reservoir. Porosity and predicted permeability logs were used with Sequential Gaussian Simulation and co-kriging methods to construct the porosity and permeability models. The static model was then used for CO2 injection simulation purposes to understand the impact of the flow conduits, barriers, and baffles in CO2 flow in all dimensions. Similarly, the CO2 simulations allowed us to better understand the CO2 entrapment process and to estimate a more realistic and reliable CO2 storage capacity of the Unayzah reservoir in the area. To test the robustness of the model predictions, geological uncertainty quantification and a sensitivity analysis were run. Parameters such as porosity, permeability, pay thickness, anisotropy, and connectivity were analyzed as well as how various combinations between them affected the CO2 storage capacity, injectivity, and containment. This approach could improve the storage efficiency of CO2 exceeding 60%. The analyzed reservoir was found to be a promising storage site. The proposed workflow and findings of the static and dynamic modeling described in this publication could serve as a guideline methodology to test the feasibility of the imminent upcoming pilots and facilitate the large-scale deployment of this very promising technology.

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