CO2 storage capacity estimation under geological uncertainty using 3-D geological modeling of unconventional reservoir rocks in Shahejie Formation, block Nv32, China

AbstractUnderground CO2 storage is a promising technology for mitigating climate change. In this vein, the subsurface condition was inherited a lot of uncertainties that prevent the success of the CO2 storage project. Therefore, this study aims to build the 3D model under geological uncertainties for enhancing CO2 storage capacity in the Shahejie Formation (Es1), Nv32 block, China. The well logs, seismic data, and geological data were used for the construction of 3-D petrophysical models. The target study area model focused on four units (Es1 × 1, Es1 × 2, Es1 × 3, and Es1 × 4) in the Shahejie Formation. Well logs were utilized to predict petrophysical properties; the lithofacies indicated that the Shahejie Formation units are sandstone, shale, and limestone. Also, the petrophysical interpretation demonstrated that the $$Es1$$ E s 1 reservoir exhibited high percentage porosity, permeability, and medium to high net-to-gross ratios. The static model showed that there are lateral heterogeneities in the reservoir properties and lithofacies; optimal reservoir rocks exist in Es1 × 4, Es1 × 3, and Es1 × 2 units. Moreover, the pore volume of the Es1 unit was estimated from petrophysical property models, ranging between 0.554369 and 10.03771 × 106 sm3, with a total volumetric value of 20.0819 × 106 sm3 for the four reservoir units. Then, the 100–400 realizations were generated for the pore volume uncertainties assessment. In consequence, 200 realizations were determined as an optimal solution for capturing geological uncertainties. The estimation of CO2 storage capacity in the Es1 formation ranged from 15.6 to 207.9 × 109 t. This result suggests the potential of CO2 geological storage in the Shahejie Formation, China.

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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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Influence of Injection Well Location on CO2 Geological Storage Efficiency

Energies ◽

10.3390/en14248604 ◽

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.

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CO2 storage capacity estimation for a deep saline formation by static reservoir modelling: the Cretaceous Paaratte Formation, offshore Otway Basin, Victoria

The APPEA Journal ◽

10.1071/aj14022 ◽

2015 ◽

Vol 55 (1) ◽

pp. 283

Author(s):

Angie Qu ◽

Mark Bunch ◽

John Kaldi

Keyword(s):

Storage Capacity ◽

Volume Fraction ◽

Co2 Storage ◽

Total Pore Volume ◽

Effective Porosity ◽

Seismic Survey ◽

Equivalent Model ◽

3D Seismic ◽

Survey Area ◽

Net To Gross

This study used stochastic simulation to estimate the CO2 storage capacity of the Cretaceous Paaratte Formation within the Casino 3D seismic survey area of the offshore Otway Basin, Victoria. Besides interpretation results from primary hard data (well data), relative acoustic impedance was used as secondary soft (proxy) data to model the distribution of the volume fraction of shale (V-Shale). The V-Shale model provided an equivalent model of lithofacies for the clastic reservoir. V-Shale correlated well with the net-to-gross and effective porosity parameters in well log interpretation results. Collocated co-kriging was then used to model the distributions of net-to-gross and effective porosity from well profiles by stochastic co-simulation processes. Using the total pore volume (TPV) obtained from this 3D modelling and storage efficiency factors defined by US DOE-NETL (2012), the potential CO2 storage capacity of the Paaratte reservoir is estimated to be between 11.94 million tonnes (P90) and 128.75 million tonnes (P10) within the geographic footprint of the Casino 3D seismic survey area. The expected TPV storage capacity (P50 confidence interval) is 46.82 million tonnes.

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