Influence of Injection Well Location on CO2 Geological Storage Efficiency

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.

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Numerical Simulation and Optimization of CO2 Sequestration in Saline Aquifers

ASME 2012 6th International Conference on Energy Sustainability, Parts A and B ◽

10.1115/es2012-91006 ◽

2012 ◽

Cited By ~ 1

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.

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

10.2523/iptc-21859-ms ◽

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.

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

The APPEA Journal ◽

10.1071/aj18191 ◽

2019 ◽

Vol 59 (1) ◽

pp. 357 ◽

Cited By ~ 3

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.

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Application of a dual tubing CO2 injection-water production horizontal well pattern for improving the CO2 storage capacity and reducing the CAPEX: A case study in Pohang basin, Korea

International Journal of Greenhouse Gas Control ◽

10.1016/j.ijggc.2019.102813 ◽

2019 ◽

Vol 90 ◽

pp. 102813 ◽

Cited By ~ 1

Author(s):

Min Kim ◽

Hyundon Shin

Keyword(s):

Horizontal Well ◽

Storage Capacity ◽

Co2 Storage ◽

Co2 Injection ◽

Water Production ◽

Well Pattern ◽

Injection Water ◽

Pohang Basin

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

The APPEA Journal ◽

10.1071/aj03033 ◽

2004 ◽

Vol 44 (1) ◽

pp. 653 ◽

Cited By ~ 1

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.

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

The APPEA Journal ◽

10.1071/aj17041 ◽

2018 ◽

Vol 58 (1) ◽

pp. 44 ◽

Cited By ~ 5

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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