Effect of the number of water alternating CO2 injection cycles on CO2 trapping capacity

2019 ◽  
Vol 59 (1) ◽  
pp. 357 ◽  
Author(s):  
Emad A. Al-Khdheeawi ◽  
Stephanie Vialle ◽  
Ahmed Barifcani ◽  
Mohammad Sarmadivaleh ◽  
Stefan Iglauer
Keyword(s):  
Storage Capacity ◽  
Co2 Storage ◽  
Storage Period ◽  
Co2 Injection ◽  
Co2 Leakage ◽  
Storage Efficiency ◽  
Reservoir Model ◽  
Plume Migration ◽  
The Impact ◽  
Injection Cycle

The CO2 storage capacity is greatly affected by CO2 injection scenario – i.e. water alternating CO2 (WACO2) injection, intermittent injection, and continuous CO2 injection – and WACO2 injection strongly improves the CO2 trapping capacity. However, the impact of the number of WACO2 injection cycles on CO2 trapping capacity is not clearly understood. Thus, we developed a 3D reservoir model to simulate WACO2 injection in deep reservoirs testing different numbers of WACO2 injection cycles (i.e. one, two, and three), and the associated CO2 trapping capacity and CO2 plume migration were predicted. For all different WACO2 injection cycle scenarios, 5000 kton of CO2 and 5000 kton of water were injected at a depth of 2275m and 2125m respectively, during a 10-year injection period. Then, a 100-year CO2 storage period was simulated. Our simulation results clearly showed, after 100 years of storage, that the number of WACO2 cycles affected the vertical CO2 leakage and the capacity of trapped CO2. The results showed that increasing the number of WACO2 cycles decreased the vertical CO2 leakage. Furthermore, a higher number of WACO2 cycles increased residual trapping, and reduced solubility trapping. Thus, the number of WACO2 cycles significantly affected CO2 storage efficiency, and higher numbers of WACO2 cycles improved CO2 storage capacity.

scholarly journals Influence of Injection Well Location on CO2 Geological Storage Efficiency

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8604
Author(s):  
Katarzyna Luboń
Keyword(s):  
Storage Capacity ◽  
Co2 Storage ◽  
Lower Jurassic ◽  
Injection Well ◽  
Co2 Injection ◽  
Storage Efficiency ◽  
Carbon Dioxide Injection ◽  
Reservoir Properties ◽  
Deep Aquifers ◽  
Well Location

An analysis of the influence of injection well location on CO2 storage efficiency was carried out for three well-known geological structures (traps) in deep aquifers of the Lower Jurassic Polish Lowlands. Geological models of the structures were used to simulate CO2 injection at fifty different injection well locations. A computer simulation showed that the dynamic CO2 storage capacity varies depending on the injection well location. It was found that the CO2 storage efficiency for structures with good reservoir properties increases with increasing distance of the injection well from the top of the structure and with increasing depth difference to the top of the structure. The opposite is true for a structure with poor reservoir properties. As the quality of the petrophysical reservoir parameters (porosity and permeability) improves, the location of the injection well becomes more important when assessing the CO2 storage efficiency. Maps of dynamic CO2 storage capacity and CO2 storage efficiency are interesting tools to determine the best location of a carbon dioxide injection well in terms of gas storage capacity.

Impact of faults and compartmentalisation on geological carbon storage estimates in highly faulted basins

2017 ◽  
Vol 57 (2) ◽  
pp. 789
Author(s):  
Jorik W. Poesse ◽  
Ludovic P. Ricard ◽  
Allison Hortle
Keyword(s):  
Carbon Storage ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Fault Reactivation ◽  
Hydrocarbon Exploration ◽  
Co2 Injection ◽  
Exploration And Production ◽  
Order Of Magnitude ◽  
Fault Permeability ◽  
The Impact

Faults have extensively been studied for hydrocarbon exploration and production; however, previous studies on fault behaviour for geological carbon storage have focused on sealing capacity or reactivation potential during injection or post-injection phases. Little is known on the impact of faults for estimating storage capacity in highly faulted basins. A geological conceptual model of a representative compartment was designed to identify the key drivers of storage capacity estimates in highly faulted basins. An uncertainty quantification framework was then designed upon this model to address the impact of geological uncertainties such as fault permeability, reservoir injectivity, compartment geometry and closure on the compartment storage capacity. Pressure-limited storage capacity was estimated from numerical simulation of CO2 injection under the constraints of maximum bottom hole pressure and fault reactivation pressure. Interpretation of the simulation results highlights that (1) two injection regimes are observed: borehole- or fault-controlled, (2) storage capacity can vary more than an order of magnitude, (3) fault and reservoir permeability can be regarded as the most influential properties with respect to storage capacity, (4) compartment geometry mainly influences the injection regime controlling the storage capacity and (5) the large sensitivity of storage capacity to the type of enclosure and fault permeability indicates that pressure build-up at the fault is often the deciding factor for CO2 storage capacity.

scholarly journals Modelling of CO2 Injection in Fluvial Sedimentary Heterogeneous Reservoirs to Assess the Impact of Geological Heterogeneities on CO2 Storage Capacity and Performance

2013 ◽  
Vol 37 ◽  
pp. 5181-5190 ◽  
Author(s):  
Benoît Issautier ◽  
Simon Fillacier ◽  
Yann Le Gallo ◽  
Pascal Audigane ◽  
Christophe Chiaberge ◽  
...  
Keyword(s):  
Storage Capacity ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Heterogeneous Reservoirs ◽  
And Performance ◽  
The Impact

Offshore MMV Planning for Sustainability of CO2 Storage in a Depleted Carbonate Reservoir, Malaysia

2021 ◽  
Author(s):  
Pankaj Kumar Tiwari ◽  
Debasis Priyadarshan Das ◽  
Parimal Arjun Patil ◽  
Prasanna Chidambaram ◽  
Zoann Low ◽  
...  
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
Carbonate Reservoir ◽  
Co2 Injection ◽  
Storage Site ◽  
Gas Field ◽  
Plume Migration ◽  
Co2 Plume ◽  
The Impact

Abstract CO2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, Measurement and Verification (MMV) planning of CO2 sequestration is crucial along with geological site selection, transportation and injection process. Several geological formations have been evaluated in the past for potential storage site which divulges the containment capacity of identified large, depleted gas reservoirs as well as long term conformance. Offshore environment makes MMV plan challenging and demands rigorous integration of monitoring technologies to optimize project economic and involved logistics. The role of MMV is critical for sustainability of the CO2 storage project as it ensures that injected CO2 in the reservoir is intact and safely stored for hundreds of years post-injection. Field specific MMV technologies for CO2 plume migration with proactive approach were identified after exercising pre-defined screening criteria. Marine CO2 dispersion study is carried out to confirm the impact of any potential leakage along existing wells and faults, and to understand the CO2 behavior in marine environment in the event of leakage. Study incorporates integration of G&G subsurface and Meta-Ocean & Environment data along with other leakage character information. Multi-Fiber Optic Sensors System (M-FOSS) to be installed in injector wells for monitoring well & reservoir integrity, overburden integrity and monitoring of early CO2 plume migration by acquiring & analyzing the distributed sensing data (DTS/DPS/DAS/DSS). Based on 3D couple modeling, a maximum injection rate of approximately 200 MMscfd of permeate stream produced from a high CO2 contaminated gas field can be achieved. Injectivity studies indicate that over 100 MMSCFD of CO2 injection rates into depleted gas reservoir is possible from a single injector. Injectivity results are integrated with dynamic simulation to determine number and location of injector wells. 3D DAS-VSP simulation results show that a subsurface coverage of approximately 3 km2 per well is achievable, which along with simulated CO2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. As planned injector wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume. To overcome this challenge, requirement of surface seismic acquisition survey is recommended for full field monitoring. An integrated MMV plan is designed for cost-effective long-term offshore monitoring of CO2 plume migration. The present study discusses the impacting parameters which make the whole process environmentally sustainable, economically viable and adhering to national and international regulations.

scholarly journals The impact of boundary conditions on CO2 storage capacity estimation in aquifers

2011 ◽  
Vol 4 ◽  
pp. 4828-4834 ◽  
Author(s):  
D.J. Smith ◽  
D.J. Noy ◽  
S. Holloway ◽  
R.A. Chadwick
Keyword(s):  
Boundary Conditions ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Capacity Estimation ◽  
The Impact

scholarly journals Numerical Simulation and Optimization of CO2 Sequestration in Saline Aquifers

2012 ◽  
Author(s):  
Zheming Zhang ◽  
Ramesh Agarwal
Keyword(s):  
Numerical Simulation ◽  
Co2 Sequestration ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Injection Well ◽  
Co2 Injection ◽  
Great Promise ◽  
Saline Aquifer ◽  
Simulation And Optimization ◽  
Co2 Plume

With recent concerns on CO2 emissions from coal fired electricity generation plants; there has been major emphasis on the development of safe and economical Carbon Dioxide Capture and Sequestration (CCS) technology worldwide. Saline reservoirs are attractive geological sites for CO2 sequestration because of their huge capacity for sequestration. Over the last decade, numerical simulation codes have been developed in U.S, Europe and Japan to determine a priori the CO2 storage capacity of a saline aquifer and provide risk assessment with reasonable confidence before the actual deployment of CO2 sequestration can proceed with enormous investment. In U.S, TOUGH2 numerical simulator has been widely used for this purpose. However at present it does not have the capability to determine optimal parameters such as injection rate, injection pressure, injection depth for vertical and horizontal wells etc. for optimization of the CO2 storage capacity and for minimizing the leakage potential by confining the plume migration. This paper describes the development of a “Genetic Algorithm (GA)” based optimizer for TOUGH2 that can be used by the industry with good confidence to optimize the CO2 storage capacity in a saline aquifer of interest. This new code including the TOUGH2 and the GA optimizer is designated as “GATOUGH2”. It has been validated by conducting simulations of three widely used benchmark problems by the CCS researchers worldwide: (a) Study of CO2 plume evolution and leakage through an abandoned well, (b) Study of enhanced CH4 recovery in combination with CO2 storage in depleted gas reservoirs, and (c) Study of CO2 injection into a heterogeneous geological formation. Our results of these simulations are in excellent agreement with those of other researchers obtained with different codes. The validated code has been employed to optimize the proposed water-alternating-gas (WAG) injection scheme for (a) a vertical CO2 injection well and (b) a horizontal CO2 injection well, for optimizing the CO2 sequestration capacity of an aquifer. These optimized calculations are compared with the brute force nearly optimized results obtained by performing a large number of calculations. These comparisons demonstrate the significant efficiency and accuracy of GATOUGH2 as an optimizer for TOUGH2. This capability holds a great promise in studying a host of other problems in CO2 sequestration such as how to optimally accelerate the capillary trapping, accelerate the dissolution of CO2 in water or brine, and immobilize the CO2 plume.

GEOLOGICAL STORAGE OF CARBON DIOXIDE: MODELLING THE EARLY CRETACEOUS SUCCESSION IN THE BARROW SUB-BASIN, NORTHWEST AUSTRALIA

2004 ◽  
Vol 44 (1) ◽  
pp. 653 ◽  
Author(s):  
C.M. Gibson-Poole ◽  
J.E. Streit ◽  
S.C. Lang ◽  
A.L. Hennig ◽  
C.J. Otto
Keyword(s):  
Storage Capacity ◽  
Flow Direction ◽  
Co2 Storage ◽  
Column Height ◽  
Co2 Injection ◽  
Technical Solution ◽  
Exit Point ◽  
Geological Storage ◽  
Migration Pathways ◽  
Northwest Australia

Potential sites for geological storage of CO2 require detailed assessment of storage capacity, containment potential and migration pathways. A possible candidate is the Flag Sandstone of the Barrow Sub-basin, northwest Australia, sealed by the Muderong Shale. The Flag Sandstone consists of a series of stacked, amalgamated, basin floor fan lobes with good lateral interconnectivity. The main reservoir sandstones have high reservoir quality with an average porosity of 21% and an average permeability of about 1,250 mD. The Muderong Shale has excellent seal capacity, with the potential to withhold an average CO2 column height of 750 m. Other containment issues were addressed by in situ stress and fault stability analysis. An average orientation of 095°N for the maximum horizontal stress was estimated. The stress regime is strike-slip at the likely injection depth (below 1,800 m). Most of the major faults in the study area have east-northeast to northeast trends and failure plots indicate that some of these faults may be reactivated if CO2 injection pressures are not monitored closely. Where average fault dips are known, maximum sustainable formation pressures were estimated to be less than 27 MPa at 2 km depth. Hydrodynamic modelling indicated that the pre-production regional formation water flow direction was from the sub-basin margins towards the centre, with an exit point to the southwest. However, this flow direction and rate have been altered by a hydraulic low in the eastern part of the sub-basin due to hydrocarbon production. The integrated site analysis indicates a potential CO2 storage capacity in the order of thousands of Mtonnes. Such capacity for geological storage could provide a technical solution for reducing greenhouse gas emissions.

Impact of injected water salinity on CO2 storage efficiency in homogenous reservoirs

2018 ◽  
Vol 58 (1) ◽  
pp. 44 ◽  
Author(s):  
Emad A. Al-Khdheeawi ◽  
Stephanie Vialle ◽  
Ahmed Barifcani ◽  
Mohammad Sarmadivaleh ◽  
Stefan Iglauer
Keyword(s):  
Co2 Storage ◽  
Water Injection ◽  
Water Salinity ◽  
Co2 Injection ◽  
Storage Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection ◽  
Wag Injection

Water alternating gas (WAG) injection significantly improves enhanced oil recovery efficiency by improving the sweep efficiency. However, the impact of injected water salinity during WAG injection on CO2 storage efficiency has not been previously demonstrated. Thus, a 3D reservoir model has been developed for simulating CO2 injection and storage processes in homogeneous reservoirs with different water injection scenarios (i.e. low salinity water injection (1000 ppm NaCl), high salinity water injection (250 000 ppm NaCl) and no water injection), and the associated reservoir-scale CO2 plume dynamics and CO2 dissolution have been predicted. Furthermore, in this work, we have investigated the efficiency of dissolution trapping with and without WAG injection. For all water injection scenarios, 5000 kton of CO2 were injected during a 10-year CO2 injection period. For high and low salinity water injection scenarios, 5 cycles of CO2 injection (each cycle is one year) at a rate of 1000 kton/year were carried out, and each CO2 cycle was followed by a one year water injection at a rate of 0.015 pore volume per year. This injection period was followed by a 500-year post injection (storage) period. Our results clearly indicate that injected water salinity has a significant impact on the quantity of dissolved CO2 and on the CO2 plume dynamics. The low salinity water injection resulted in the maximum CO2 dissolution and minimum vertical migration of CO2. Also, our results show that WAG injection enhances dissolution trapping and reduces CO2 leakage risk for both injected water salinities. Thus, we conclude that the low salinity water injection improves CO2 storage efficiency.

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