scholarly journals Pore Pressure Analysis for Distinguishing Earthquakes Induced by CO2 Injection from Natural Earthquakes

2020 ◽  
Vol 12 (22) ◽  
pp. 9723
Author(s):  
Chanmaly Chhun ◽  
Takeshi Tsuji
Keyword(s):  
Pore Pressure ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Storage Site ◽  
Seasonal Fluctuations ◽  
Induced Earthquakes ◽  
Seismogenic Fault ◽  
Seismogenic Faults ◽  
Natural Earthquakes

It is important to distinguish between natural earthquakes and those induced by CO2 injection at carbon capture and storage sites. For example, the 2004 Mw 6.8 Chuetsu earthquake occurred close to the Nagaoka CO2 storage site during gas injection, but we could not quantify whether the earthquake was due to CO2 injection or not. Here, changes in pore pressure during CO2 injection at the Nagaoka site were simulated and compared with estimated natural seasonal fluctuations in pore pressure due to rainfall and snowmelt, as well as estimated pore pressure increases related to remote earthquakes. Changes in pore pressure due to CO2 injection were clearly distinguished from those due to rainfall and snowmelt. The simulated local increase in pore pressure at the seismogenic fault area was much less than the seasonal fluctuations related to precipitation and increases caused by remote earthquakes, and the lateral extent of pore pressure increase was insufficient to influence seismogenic faults. We also demonstrated that pore pressure changes due to distant earthquakes are capable of triggering slip on seismogenic faults. The approach we developed could be used to distinguish natural from injection-induced earthquakes and will be useful for that purpose at other CO2 sequestration sites.

scholarly journals Pore Pressure Analysis for Distinguishing Earthquakes Induced by CO2 Injection from Natural Earthquakes

2020 ◽  
Author(s):  
Chanmaly Chhun ◽  
Takeshi Tsuji
Keyword(s):  
Pore Pressure ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Storage Site ◽  
Seasonal Fluctuations ◽  
Induced Earthquakes ◽  
Seismogenic Fault ◽  
Seismogenic Faults ◽  
Natural Earthquakes

It is important to distinguish between natural earthquakes and those induced by CO2 injection at carbon capture and storage sites. For example, the 2004 Mw 6.8 Chuetsu earthquake occurred close to the Nagaoka CO2 storage site during gas injection, but we could not quantify whether the earthquake was due to CO2 injection or not. Here we simulated changes of pore pressure during CO2 injection at the Nagaoka site and compared them with estimated natural seasonal fluctuations of pore pressure due to rainfall and snowmelt as well as estimated pore pressure increases related to remote earthquakes. We clearly distinguished changes of pore pressure due to CO2 injection from those due to rainfall and snowmelt. The simulated local increase in pore pressure at seismogenic fault area was much less than the seasonal fluctuations related to precipitation and increases caused by remote earthquakes, and the lateral extent of pore pressure increase was insufficient to influence seismogenic faults. We also demonstrated that pore pressure changes due to distant earthquakes are capable of triggering slip on seismogenic faults. The approach we developed could be used to distinguish natural from injection-induced earthquakes and will be useful for that purpose at other CO2 sequestration sites.

Natural and artificial pore pressure variation for distinguishing earthquakes induced by CO2 injection from natural earthquakes

2021 ◽  
Author(s):  
Chanmaly Chhun ◽  
Takeshi Tsuji
Keyword(s):  
Pore Pressure ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Storage Site ◽  
Seasonal Fluctuations ◽  
Induced Earthquakes ◽  
Seismogenic Fault ◽  
Seismogenic Faults ◽  
Natural Earthquakes

<p>It is important to distinguish between natural earthquakes and those induced by CO<sub>2</sub> injection at carbon capture and storage sites. For example, the 2004 M<sub>w</sub> 6.8 Chuetsu earthquake occurred close to the Nagaoka CO<sub>2</sub> storage site during gas injection, but we could not quantify whether the earthquake was due to CO<sub>2</sub> injection or not. Here, changes in pore pressure during CO<sub>2</sub> injection at the Nagaoka site were simulated and compared with estimated natural seasonal fluctuations in pore pressure due to rainfall and snowmelt, as well as estimated pore pressure increases related to remote earthquakes. Changes in pore pressure due to CO<sub>2</sub> injection were clearly distinguished from those due to rainfall and snowmelt. The simulated local increase in pore pressure at the seismogenic fault area was much less than the seasonal fluctuations related to precipitation and increases caused by remote earthquakes, and the lateral extent of pore pressure increase was insufficient to influence seismogenic faults. We also demonstrated that pore pressure changes due to distant earthquakes are capable of triggering slip on seismogenic faults. The approach we developed could be used to distinguish natural from injection-induced earthquakes and will be useful for that purpose at other CO<sub>2</sub> sequestration sites.</p><p>This research was published in “Sustainability”, https://doi.org/10.3390/su12229723.</p><p>Keywords: pore pressure; CO2 injection; induced earthquakes; seasonal earthquakes; remote earthquakes; seismogenic faults.</p>

scholarly journals Managing Uncertainty in Geological CO2 Storage Using Bayesian Evidential Learning

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1557
Author(s):  
Amine Tadjer ◽  
Reidar B. Bratvold
Keyword(s):  
Uncertainty Quantification ◽  
History Matching ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Monitoring Program ◽  
Co2 Injection ◽  
Drinking Water Contamination ◽  
Model Inversion ◽  
Geological Co2 Storage ◽  
And Storage

Carbon capture and storage (CCS) has been increasingly looking like a promising strategy to reduce CO2 emissions and meet the Paris agreement’s climate target. To ensure that CCS is safe and successful, an efficient monitoring program that will prevent storage reservoir leakage and drinking water contamination in groundwater aquifers must be implemented. However, geologic CO2 sequestration (GCS) sites are not completely certain about the geological properties, which makes it difficult to predict the behavior of the injected gases, CO2 brine leakage rates through wellbores, and CO2 plume migration. Significant effort is required to observe how CO2 behaves in reservoirs. A key question is: Will the CO2 injection and storage behave as expected, and can we anticipate leakages? History matching of reservoir models can mitigate uncertainty towards a predictive strategy. It could prove challenging to develop a set of history matching models that preserve geological realism. A new Bayesian evidential learning (BEL) protocol for uncertainty quantification was released through literature, as an alternative to the model-space inversion in the history-matching approach. Consequently, an ensemble of previous geological models was developed using a prior distribution’s Monte Carlo simulation, followed by direct forecasting (DF) for joint uncertainty quantification. The goal of this work is to use prior models to identify a statistical relationship between data prediction, ensemble models, and data variables, without any explicit model inversion. The paper also introduces a new DF implementation using an ensemble smoother and shows that the new implementation can make the computation more robust than the standard method. The Utsira saline aquifer west of Norway is used to exemplify BEL’s ability to predict the CO2 mass and leakages and improve decision support regarding CO2 storage projects.

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 The Endurance CO2 storage site, Blocks 42/25 and 43/21, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 163-171 ◽  
Author(s):  
Jon G. Gluyas ◽  
Usman Bagudu
Keyword(s):  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Lower Triassic ◽  
Injection Rate ◽  
Government Support ◽  
Storage Site ◽  
Sandstone Formation ◽  
The Uk ◽  
And Storage

AbstractThe Endurance, four-way, dip-closed structure in UK Blocks 42/25 and 43/21 occurs over a salt swell diapir and within Triassic and younger strata. The Lower Triassic Bunter Sandstone Formation reservoir within the structure was tested twice for natural gas (in 1970 and 1990) but both wells were dry. The reservoir is both thick and high quality and, as such, an excellent candidate site for subsurface CO2 storage.In 2013 a consortium led by National Grid Carbon drilled an appraisal well on the structure and undertook an injection test ahead of a planned development of Endurance as the first bespoke storage site on the UK Continental Shelf with an expected injection rate of 2.68 × 106 t of dense phase CO2 each year for 20 years. The site was not developed following the UK Government's removal of financial support for carbon capture and storage (CCS) demonstration projects, but it is hoped with the recent March 2020 Budget that government support for CCS may now be back on track.

ASSESSING RISK IN CO2 STORAGE PROJECTS

2004 ◽  
Vol 44 (1) ◽  
pp. 677 ◽  
Author(s):  
A.R. Bowden ◽  
A. Rigg
Keyword(s):  
Risk Assessment ◽  
Best Practice ◽  
Co2 Storage ◽  
Assessment Method ◽  
Assessment Process ◽  
Co2 Injection ◽  
Base Case ◽  
Environmental Damage ◽  
Storage Site ◽  
Geological Storage

A key challenge to researchers involved with geological storage of CO2 has been to develop an appropriate methodology to assess and compare alternative CO2 injection projects on the basis of risk. Technical aspects, such as the risk of leakage and the effectiveness of the intended reservoir, clearly need to be considered, but so do less tangible aspects such as the value and safety of geological storage of CO2, and potential impacts on the community and environment.The RISQUE method has been applied and found to be an appropriate approach to deliver a transparent risk assessment process that can interface with the wider community and allow stakeholders to assess whether the CO2 injection process is safe, measurable and verifiable and whether a selected alternative delivers cost-effective greenhouse benefits.In Australia, under the GEODISC program, the approach was applied to assess the risk posed by conceptual CO2 injection projects in four selected areas: Dongara, Petrel, Gippsland and Carnarvon. The assessment derived outputs that address key project performance indicators that:are useful to compare projects;include technical, economic and community risk events;assist communication of risk to stakeholders;can be incorporated into risk management design of injection projects; andhelp identify specific areas for future research.The approach is to use quantitative techniques to characterise risk in terms of both the likelihood of identified risk events occurring (such as CO2 escape and inadequate injectivity into the storage site) and of their consequences (such as environmental damage and loss of life). The approach integrates current best practice risk assessment methods with best available information provided by an expert panel.The results clearly showed the relationships between containment and effectiveness for all of the four conceptual CO2 injection projects and indicated their acceptability with respect to two KPIs. Benefit-cost analysis showed which projects would probably be viable considering base-case economics, greenhouse benefits, and also the case after risk is taken into account. A societal risk profile was derived to compare the public safety risk posed by the injection projects with commonly accepted engineering target guidelines used for dams. The levels of amenity risk posed to the community by the projects were assessed, and their acceptability with respect to the specific KPI was evaluated.The risk assessment method and structure that was used should be applied to other potential CO2 injection sites to compare and rank their suitability, and to assist selection of the most appropriate site for any injection project. These sites can be reassessed at any time, as further information becomes available.

Effective Prediction and Management of a CO2 Flooding Process for Enhancing Oil Recovery Using Artificial Neural Networks

2017 ◽  
Vol 140 (3) ◽  
Author(s):  
Si Le Van ◽  
Bo Hyun Chon
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Environmental Benefits ◽  
Co2 Production ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Injection Process ◽  
Artificial Neural

The injection of CO2 has been in global use for enhanced oil recovery (EOR) as it can improve oil production in mature fields. It also has environmental benefits for reducing greenhouse carbon by permanently sequestrating CO2 (carbon capture and storage (CCS)) in reservoirs. As a part of numerical studies, this work proposed a novel application of an artificial neural network (ANN) to forecast the performance of a water-alternating-CO2 process and effectively manage the injected CO2 in a combined CCS–EOR project. Three targets including oil recovery, net CO2 storage, and cumulative gaseous CO2 production were quantitatively simulated by three separate ANN models for a series of injection frames of 5, 15, 25, and 35 cycles. The concurrent estimations of a sequence of outputs have shown a relevant application in scheduling the injection process based on the progressive profile of the targets. For a specific surface design, an increment of 5.8% oil recovery and 4% net CO2 storage was achieved from 25 cycles to 35 cycles, suggesting ending the injection at 25 cycles. Using the models, distinct optimizations were also computed for oil recovery and net CO2 sequestration in various reservoir conditions. The results expressed a maximum oil recovery from 22% to 30% oil in place (OIP) and around 21,000–29,000 tons of CO2 trapped underground after 35 cycles if the injection began at 60% water saturation. The new approach presented in this study of applying an ANN is obviously effective in forecasting and managing the entire CO2 injection process instead of a single output as presented in previous studies.

South West Hub Project: appraising a carbon storage resource in Western Australia

2015 ◽  
Vol 55 (2) ◽  
pp. 472
Author(s):  
Linda Stalker ◽  
Dominique Van Gent ◽  
Sandeep Sharma ◽  
Martin Burke
Keyword(s):  
Carbon Storage ◽  
Carbon Capture ◽  
Local Community ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Relevant Information ◽  
Seismic Survey ◽  
Storage Site ◽  
South West ◽  
Commercial Scale

The South West Hub Carbon Capture and Storage Project (SWH), managed by the WA Department of Mines and Petroleum (WA DMP), is evaluating the potential for a commercial-scale carbon storage site near major emissions sites in southwest WA. The area under investigation is in the southern Perth Basin, focusing on a 150 km2 area in the shires of Harvey and Waroona. WA DMP is conducting a major feasibility study and collecting pre-competitive data in partnership with the local community. The activities are done in a stage-gate model to obtain relevant information on the potential storage capacity, containment security and injectivity of the geology. Following a smaller 2D seismic survey and the drilling of the Harvey–1 stratigraphic well, a more complex 3D seismic survey was undertaken in February to March, 2014. These activities have confirmed the potential for commercial-scale CO2 storage. A new work package has been initiated with the drilling of three wells (Harvey–2, –3 and –4) underway and plans to drill a fifth well in the next 12 months. The stage-gate approach has been cost-effective, resulting in a carefully planned data acquisition and research program. The approach allows new results, information and potential future activities to be rolled out to stakeholders and the community in the area.

Integrated Coupled Modelling Study to Assess CO2 Sequestration Potential in a Depleted Gas Field

2021 ◽  
Author(s):  
Ahmad Ismail Azahree ◽  
Farhana Jaafar Azuddin ◽  
Siti Syareena Mohd Ali ◽  
Muhammad Hamzi Yakup ◽  
Mohd Azlan Mustafa ◽  
...  
Keyword(s):  
Storage Capacity ◽  
Co2 Storage ◽  
Coupled Model ◽  
Co2 Injection ◽  
Storage Site ◽  
Coupled Modeling ◽  
Reservoir Properties ◽  
Gas Field ◽  
Sequestration Potential ◽  
Injection Phase

Abstract A depleted gas field is selected as CO2 storage site for future high CO2 content gas field development in Malaysia. The reservoir selected is a carbonate buildup of middle to late Miocene age. This paper describes an integrated modeling approach to evaluate CO2 sequestration potential in depleted carbonate gas reservoir. Integrated dynamic-geochemical and dynamic-geomechanics coupled modeling is required to properly address the risks and uncertainties such as, effect of compaction and subsidence during post-production and injection. The main subsurface uncertainties for assessing the CO2 storage potential are (i) CO2 storage capacity due to higher abandonment pressure (ii) CO2 containment due to geomechanical risks (iii) change in reservoir properties due to reaction of reservoir rock with injected CO2. These uncertainties have been addressed by first building the compositional dynamic model adequately history matched to the production data, and then coupling with geomechanical model and geochemical module during the CO2 injection phase. This is to further study on the trapping mechanisms, caprock integrity, compaction-subsidence implication towards maximum storage capacity and injectivity. The initial standalone dynamic modeling poses few challenges to match the water production in the field due to presence of karsts, extent of a baffle zone between the aquifer and producing zones and uncertainty in the aquifer volume. The overall depletion should be matched, since the field abandonment pressure impacts the CO2 injectivity and storage capacity. A reasonably history matched coupled dynamic-geomechanical model is used as base case for simulating CO2 injection. The dynamic-geomechanical coupling is done with 8 stress steps based on critical pressure changes throughout production and CO2 injection phase. Overburden and reservoir properties has been mapped in Geomechanical grid and was run using two difference constitutive model; Mohr's Coulomb and Modified Cam Clay respectively. The results are then calibrated with real subsidence measurement at platform location. This coupled model has been used to predict the maximum CO2 injection rate of 100 MMscf/d/well and a storage capacity of 1.34 Tscf. The model allows to best design the injection program in terms of well location, target injection zone and surface facilities design. This coupled modeling study is used to mature the field as a viable storage site. The established workflow starting from static model to coupled model to forecasting can be replicated in other similar projects to ensure the subsurface robustness, reduce uncertainty and risk mitigation of the field for CO2 storage site.

Reservoir Characterization for Uncertainty Analysis and Its Impact on CO2 Injection and Sequestration in a Depleted Offshore Carbonate Gas Field

2021 ◽  
Author(s):  
Debasis P. Das ◽  
Parimal A. Patil ◽  
Pankaj K. Tiwari ◽  
Renato J Leite ◽  
Raj Deo Tewari
Keyword(s):  
Co2 Storage ◽  
Assessment Process ◽  
Rock Properties ◽  
Co2 Injection ◽  
Storage Site ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Well Integrity ◽  
Seismic Anomalies

Abstract The emerging global climate change policies have necessitated the strategic need for prudent management of produced contaminants and, with cold flaring being no more the best option, Carbon Capture Utilization & Storage (CCUS) technology provides opportunity for development of high CO2 contaminant fields. A typical CO2 sequestration project comprises capturing CO2 by separating from produced hydrocarbons followed by injection of CO2 into deep geological formations for long term storage. While injection ofCO2 may continue over tens of years, the long-term containment needs to be ascertained for thousands of years. Several geological and geophysical factors along with the existingwells need to be evaluated to assess the potential risks for CO2 leakage that maychallenge the long-term containment. This study considers a depleted carbonate field located offshore Sarawak as a possible long-term CO2 storage site. Elements that may lead to possible leakage of CO2over time are the existing faults or fractures, development of new fractures/faults during injection, caprock failure due to pressures exceeding fracture pressure during/after injection and possible leakage through existing wells. The risk assessment process includes identification and mapping of faults and fracture networks, mapping of seals, evaluation of seismic anomalies and gas while drilling records, pore-pressure analysis, laboratory experiments for analyzing changes in geomechanical & geochemical rock properties and well integrity of existing wells. All these parameters are cross correlated, and qualitative risk categorization is carried out to determine the robustness of the reservoir for long term CO2 storage. The evaluation of available data indicates less frequent faulting occur only towards the flank with no seismic anomalies associated with them. Some seismic anomalies are observed at shallower levels, however their impact on the reservoir and overburden integrity is assessed to be minimum. There are four shale dominated formations mapped in the overburden section, which will act as potential seals. Estimated fracture pressures for the potential seals ranges between 6200-9280 psia for the deepest seal to 2910-4290 psia for the shallowest. Therefore,it is interpreted that if the post injection reservoir pressure is kept below the initial reservoir pressure of 4480 psia, it would not hold any threat to the caprock integrity.Leakage rate riskalong the existing wells was determined based on well log data. Well integrity check of legacywells helped identify two abandoned wells for rigorous remediation to restore their integrity. The subsurface risk analysis is critical to ascertain the long-term containment of injectedCO2. The integrated subsurface characterization and well integrity analysis approach adopted in this work can be applied to any other field/reservoir to validate its robustness for long-term CO2 injection and storage.

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