Simultaneous CO2 injection and water production to optimise aquifer storage capacity

Abstract In recent years, carbon neutrality has emerged as an important social and political focus globally, where carbon sequestration plays a key role. The present work is aimed at introducing ASCAPE (Aquifer Storage CAPacity Evaluation tool), a fast and flexible tool useful in case of CO2 aquifer sequestration to preliminarily evaluate the required storage capacity as a function of the maximum allowable pressure increment. ASCAPE is based on the volumetric method included in SPE "Guidelines for Applications of the CO2 Storage Resources Management System" (SPE, 2020) for aquifer sequestration. The analytical formula was integrated to include additional physical phenomena as CO2 solubility in water, pressure control through water production, effect of gas pools connected to aquifer. The tool, implemented in Excel/VBA environment, allows to easily obtain a theoretical Pressure increment vs. Aquifer Volume curve useful to estimate the required aquifer volume to store a given quantity of CO2. ASCAPE results were validated comparing to a simplified 3D model simulated by a compositional commercial dynamic simulator. The validation showed a very good alignment with the 3D dynamic simulation results under several conditions. Many tests were performed with and without the CO2 solubility model, demonstrating that this phenomenon acts as pressure increment reducer. The original volumetric model can be therefore considered slightly conservative, since it neglects this physical contribution, which allowed to improve the reliability of the proposed analytical model. The proposed methodology is a general-purpose application being not related to a specified candidate and, therefore, it can be tailored on the specific scenario to be evaluated. ASCAPE was developed for preliminary screening of CO2 sequestration concepts in greenfield development areas, where the absence of brown or exhausted fields makes the storage in aquifer the only viable solution. Different aquifers were compared under certain assumptions of carbon to be stored with and without water production, allowing a preliminary evaluation that will be used to rank the concepts in terms of technical/economic feasibility.

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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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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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Evaluation of CO2 Aquifer storage capacity in the vicinity of a large emission area in Japan: Case history of Osaka Bay

Energy Procedia ◽

10.1016/j.egypro.2009.02.039 ◽

2009 ◽

Vol 1 (1) ◽

pp. 2701-2708 ◽

Cited By ~ 3

Author(s):

Tsutomu Hashimoto ◽

Shin-ichi Hiramatsu ◽

Takashi Yamamoto ◽

Hitoshi Takano ◽

Manabu Mizuno ◽

...

Keyword(s):

Case History ◽

Storage Capacity ◽

Aquifer Storage ◽

Osaka Bay ◽

Emission Area ◽

History Of

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Static and Dynamic Estimates of CO2-Storage Capacity in Two Saline Formations in the UK

SPE Journal ◽

10.2118/131609-pa ◽

2012 ◽

Vol 17 (04) ◽

pp. 1108-1118 ◽

Cited By ~ 9

Author(s):

M.. Jin ◽

G.. Pickup ◽

E.. Mackay ◽

A.. Todd ◽

M.. Sohrabi ◽

...

Keyword(s):

Input Data ◽

Storage Capacity ◽

Co2 Storage ◽

Total Pore Volume ◽

Static Method ◽

Initial Assessment ◽

Storage Site ◽

Aquifer Storage ◽

The Uk ◽

Migration Pathways

Summary Estimation of carbon dioxide (CO2)-storage capacity is a key step in the appraisal of CO2-storage sites. Different calculation methods may lead to widely diverging values. The compressibility method is a commonly used static method for estimating storage capacity of saline aquifers: It is simple, is easy to use, and requires a minimum of input data. Alternatively, a numerical reservoir simulation provides a dynamic method that includes Darcy flow calculations. More input data are required for dynamic simulation, and it is more computationally intensive, but it takes into account migration pathways and dissolution effects, so it is generally more accurate and more useful. For example, the CO2-migration plume may be used to identify appropriate monitoring techniques, and the analysis of the trapping mechanism for a certain site will help to optimize well location and the injection plan. Two hypothetical saline-aquifer storage sites in the UK, one in Lincolnshire and the other in the Firth of Forth, were analyzed. The Lincolnshire site has a comparatively simple geology, while the Forth site has a more complex geology. For each site, both static- and dynamic-capacity calculations were performed. In the static method, CO2 was injected until the average pressure reached a critical value. In the migration-monitoring case, CO2 was injected for 15 years, and was followed by a closure period lasting thousands of years. The fraction of dissolved CO2 and the fraction immobilized by pore-scale trapping were calculated. The results of both geological systems show that the migration of CO2 is strongly influenced by the local heterogeneity. The calculated storage efficiency for the Lincolnshire site varied between 0.34% and 0.65% of the total pore-volume, depending on whether the system boundaries were considered open or closed. Simulation of the deeper, more complex Forth geological system gave storage capacities as high as 1.05%. This work was part of the CO2-Aquifer-Storage Site Evaluation and Monitoring (CASSEM) integrated study to derive methodologies for assessment of CO2 storage in saline formations. Although static estimates are useful for initial assessment when fewer data are available, we demonstrate the value of performing dynamic storage calculations and the opportunities to identify mechanisms for optimizing the storage capacity.

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Managing geologic CO2 storage with pre-injection brine production: a strategy evaluated with a model of CO2 injection at Snøhvit

Energy & Environmental Science ◽

10.1039/c5ee03648h ◽

2016 ◽

Vol 9 (4) ◽

pp. 1504-1512 ◽

Cited By ~ 32

Author(s):

Thomas A. Buscheck ◽

Joshua A. White ◽

Susan A. Carroll ◽

Jeffrey M. Bielicki ◽

Roger D. Aines

Keyword(s):

Storage Capacity ◽

Co2 Storage ◽

Co2 Injection ◽

Geologic Co2 Storage

By removing brine from a reservoir prior to storing CO2, storage capacity can be increased by nearly an equivalent volume.

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A Novel Method for CO2 Injection that Enhances Storage Capacity and Security

74th EAGE Conference and Exhibition incorporating EUROPEC 2012 ◽

10.3997/2214-4609.20148419 ◽

2012 ◽

Author(s):

S. M. Shariatipour ◽

G. E. Pickup ◽

E. J. Mackay

Keyword(s):

Storage Capacity ◽

Co2 Injection ◽

Novel Method

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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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