Application of a Dual Tubing CO2 Injection-Water Production System Using a Horizontal Well for Improving CO2 Storage Capacity: A Case Study in Pohang Basin, Offshore South Korea

This study aims at the development of an artificial neural network (ANN) model to optimize relief well design in Pohang Basin, South Korea. Relief well design in carbon capture and geological storage (CCS) requires complex processes and excessive iterative procedures to obtain optimal operating parameters, such as CO2 injection rate, water production rate, distance between the wells, and pressure at the wells. To generate training and testing datasets for ANN model development, optimization processes for a relief well with various injection scenarios were performed. Training and testing were conducted, where the best iteration and regression were considered based on the calculated coefficient of determination (R2) and root mean square error (RMSE) values. According to validation with a 20-year injection scenario, which was not included in the training datasets, the model showed great performance with R2 values of 0.96 or higher for all the output parameters. In addition, the RMSE values for the BHP and the trapping mechanisms were lower than 0.04. Moreover, the location of the relief well was reliably predicted with a distance difference of only 20.1 m. The ANN model can be robust tool to optimize relief well design without a time-consuming reservoir simulations.

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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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Impact of CO2 mixing with trapped hydrocarbons on CO2 storage capacity and security: A case study from the Captain aquifer (North Sea)

Applied Energy ◽

10.1016/j.apenergy.2020.115634 ◽

2020 ◽

Vol 278 ◽

pp. 115634

Author(s):

Saeed Ghanbari ◽

Eric J. Mackay ◽

Niklas Heinemann ◽

Juan Alcalde ◽

Alan James ◽

...

Keyword(s):

North Sea ◽

Storage Capacity ◽

Co2 Storage

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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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Subsurface engineering of CCUS in Australia (case studies)

The APPEA Journal ◽

10.1071/aj18125 ◽

2019 ◽

Vol 59 (2) ◽

pp. 762

Author(s):

Mohammad B. Bagheri ◽

Matthias Raab

Keyword(s):

Uncertainty Analysis ◽

Case Studies ◽

Oil And Gas ◽

Co2 Storage ◽

Oil And Gas Industry ◽

Reservoir Engineering ◽

Co2 Injection ◽

Gas Industry ◽

Co2 Plume

Carbon capture utilisation and storage (CCUS) is a rapidly emerging field in the Australian oil and gas industry to address carbon emissions while securing reliable energy. Although there are similarities with many aspects of the oil and gas industry, subsurface CO2 storage has some unique geology and geophysics, and reservoir engineering considerations, for which we have developed specific workflows. This paper explores the challenges and risks that a reservoir engineer might face during a field-scale CO2 injection project, and how to address them. We first explain some of the main concepts of reservoir engineering in CCUS and their synergy with oil and gas projects, followed by the required inputs for subsurface studies. We will subsequently discuss the importance of uncertainty analysis and how to de-risk a CCUS project from the subsurface point of view. Finally, two different case studies will be presented, showing how the CCUS industry should use reservoir engineering analysis, dynamic modelling and uncertainty analysis results, based on our experience in the Otway Basin. The first case study provides a summary of CO2CRC storage research injection results and how we used the dynamic models to history match the results and understand CO2 plume behaviour in the reservoir. The second case study shows how we used uncertainty analysis to improve confidence on the CO2 plume behaviour and to address regulatory requirements. An innovative workflow was developed for this purpose in CO2CRC to understand the influence of each uncertainty parameter on the objective functions and generate probabilistic results.

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