Reservoir Architecture Modeling at Sub-Seismic Scale for a Depleted Carbonate Reef Reservoir for CO2 Storage in Sarawak Basin, Offshore Malaysia

2021 ◽  
Author(s):  
Zhong Cai ◽  
Ana Widyanita ◽  
Prasanna Chidambaram ◽  
Ernest A Jones
Keyword(s):  
Risk Mitigation ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Base Case ◽  
Reservoir Model ◽  
Seismic Reflection Data ◽  
Architecture Model ◽  
Measurement Monitoring ◽  
Reservoir Architecture ◽  
Co2 Plume

Abstract It is still a challenge to build a numerical static reservoir model, based on limited data, to characterize reservoir architecture that corresponds to the geological concept models. The numerical static reef reservoir model has been evolving from the oversimplified tank-like models, simple multi-layer models to the complex multi-layer models that are more realistic representations of complex reservoirs. A simple multi-layer model for the reef reservoir with proportional layering scheme was applied in the CO2 Storage Development Plan (SDP) study, as the most-likely scenario to match the geological complexity. Model refinement can be conducted during CO2 injection phase with Measurement, Monitoring and Verification (MMV) technologies for CO2 plume distribution tracking. The selected reservoir is a Middle to Late Miocene carbonate reef complex, with three phases of reef growth: 1) basal transgressive phase, 2) lower buildup phase, and 3) upper buildup phase. Three chronostratigraphic surfaces were identified on 3D seismic reflection data as the zone boundaries, which were then divided into sub-zones and layers. Four layering methods were compared, which are ‘proportional’, ’follow top’, ‘follow base’ and ‘follow top with reference surface’. The proportional layering method was selected for the base case of the 3D static reservoir model and the others were used in the uncertainty analysis. Based on the results of uncertainty and risk assessment, a risk mitigation for CO2 injection operation were modeled and three CO2 injection well locations were optimized. The reservoir architecture model would be updated and refined by the difference between the modeled CO2 plume patterns and The MMV results in the future.

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.

Subsurface engineering of CCUS in Australia (case studies)

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.

ASSESSING RISK IN CO2 STORAGE PROJECTS

2004 ◽  
Vol 44 (1) ◽  
pp. 677 ◽  
Author(s):  
A.R. Bowden ◽  
A. Rigg
Keyword(s):  
Risk Assessment ◽  
Best Practice ◽  
Co2 Storage ◽  
Assessment Method ◽  
Assessment Process ◽  
Co2 Injection ◽  
Base Case ◽  
Environmental Damage ◽  
Storage Site ◽  
Geological Storage

A key challenge to researchers involved with geological storage of CO2 has been to develop an appropriate methodology to assess and compare alternative CO2 injection projects on the basis of risk. Technical aspects, such as the risk of leakage and the effectiveness of the intended reservoir, clearly need to be considered, but so do less tangible aspects such as the value and safety of geological storage of CO2, and potential impacts on the community and environment.The RISQUE method has been applied and found to be an appropriate approach to deliver a transparent risk assessment process that can interface with the wider community and allow stakeholders to assess whether the CO2 injection process is safe, measurable and verifiable and whether a selected alternative delivers cost-effective greenhouse benefits.In Australia, under the GEODISC program, the approach was applied to assess the risk posed by conceptual CO2 injection projects in four selected areas: Dongara, Petrel, Gippsland and Carnarvon. The assessment derived outputs that address key project performance indicators that:are useful to compare projects;include technical, economic and community risk events;assist communication of risk to stakeholders;can be incorporated into risk management design of injection projects; andhelp identify specific areas for future research.The approach is to use quantitative techniques to characterise risk in terms of both the likelihood of identified risk events occurring (such as CO2 escape and inadequate injectivity into the storage site) and of their consequences (such as environmental damage and loss of life). The approach integrates current best practice risk assessment methods with best available information provided by an expert panel.The results clearly showed the relationships between containment and effectiveness for all of the four conceptual CO2 injection projects and indicated their acceptability with respect to two KPIs. Benefit-cost analysis showed which projects would probably be viable considering base-case economics, greenhouse benefits, and also the case after risk is taken into account. A societal risk profile was derived to compare the public safety risk posed by the injection projects with commonly accepted engineering target guidelines used for dams. The levels of amenity risk posed to the community by the projects were assessed, and their acceptability with respect to the specific KPI was evaluated.The risk assessment method and structure that was used should be applied to other potential CO2 injection sites to compare and rank their suitability, and to assist selection of the most appropriate site for any injection project. These sites can be reassessed at any time, as further information becomes available.

Long-term Strategy Optimization of Scale Squeeze Treatment in a Carbonate Reservoir Under CO2-WAG Water-Alternating-Gas Injection

2021 ◽  
Author(s):  
Vahid Azari ◽  
Hydra Rodrigues ◽  
Alina Suieshova ◽  
Oscar Vazquez ◽  
Eric Mackay
Keyword(s):  
Net Present Value ◽  
Co2 Storage ◽  
Gas Injection ◽  
Carbonate Reservoir ◽  
Co2 Injection ◽  
Base Case ◽  
Production Well ◽  
Water Alternating Gas ◽  
Gradient Descent Algorithm

Abstract The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition. Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle. The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window. The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.

scholarly journals Development of an Electrical Resistivity Tomography Monitoring Concept for the Svelvik CO<sub>2</sub> Field Lab, Norway

2020 ◽  
Vol 54 ◽  
pp. 41-53
Author(s):  
Tobias Raab ◽  
Wolfgang Weinzierl ◽  
Bernd Wiese ◽  
Dennis Rippe ◽  
Cornelia Schmidt-Hattenberger
Keyword(s):  
Electrical Resistivity ◽  
Electrical Resistivity Tomography ◽  
Co2 Storage ◽  
Pressure Effects ◽  
Co2 Injection ◽  
Target Area ◽  
Electrode Arrays ◽  
Resistivity Tomography ◽  
Monitoring Well ◽  
Co2 Plume

Abstract. Within the ERA-NET co-funded ACT project Pre-ACT (Pressure control and conformance management for safe and efficient CO2 storage – Accelerating CCS Technologies), a monitoring concept was established to distinguish between CO2 induced saturation and pore pressure effects. As part of this monitoring concept, geoelectrical cross-hole surveys have been designed and conducted at the Svelvik CO2 Field Lab, located on the Svelvik ridge at the outlet of the Drammensfjord in Norway. The Svelvik CO2 Field Lab has been established in summer 2019, and comprises four newly drilled, 100 m deep monitoring wells, surrounding an existing well used for water and CO2 injection. Each monitoring well was equipped with modern sensing systems including five types of fiber-optic cables, conventional- and capillary pressure monitoring systems, as well as electrode arrays for Electrical Resistivity Tomography (ERT) surveys. With a total of 64 electrodes (16 each per monitoring well), a large number of measurement configurations for the ERT imaging is possible, requiring the performance of the tomography to be investigated beforehand by numerical studies. We combine the free and open-source geophysical modeling library pyGIMLi with Eclipse reservoir modeling to simulate the expected behavior of all cross-well electrode configurations during the CO2 injection experiment. Simulated CO2 saturations are converted to changes in electrical resistivity using Archie's Law. Using a finely meshed resistivity model, we simulate the response of all possible measurement configurations, where always two electrodes are located in two corresponding wells. We select suitable sets of configurations based on different criteria, i.e. the ratio between the measured change in apparent resistivity in relation to the geometric factor and the maximum sensitivity in the target area. The individually selected measurement configurations are tested by inverting the synthetic ERT data on a second coarser mesh. The pre-experimental, numerical results show adequate resolution of the CO2 plume. Since less CO2 was injected during the field experiment than originally modeled, we perform post-experimental tests of the selected configurations for their potential to image the CO2 plume using revised reservoir models and injection volumes. These tests show that detecting the small amount of injected CO2 will likely not be feasible.

scholarly journals Carbon-Negative Scenarios in High CO2 Gas Condensate Reservoirs

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5898
Author(s):  
Lucija Jukić ◽  
Domagoj Vulin ◽  
Valentina Kružić ◽  
Maja Arnaut
Keyword(s):  
Natural Gas ◽  
Co2 Storage ◽  
Cost Effective ◽  
Gas Production ◽  
Gas Condensate ◽  
Co2 Injection ◽  
Base Case ◽  
Processing Plant ◽  
Gas Condensate Reservoirs ◽  
Northern Croatia

A gas condensate reservoir in Northern Croatia was used as an example of a CO2 injection site during natural gas production to test whether the entire process is carbon-negative. To confirm this hypothesis, all three elements of the CO2 life cycle were included: (1) CO2 emitted by combustion of the produced gas from the start of production from the respective field, (2) CO2 that is separated at natural gas processing plant, i.e., the CO2 that was present in the original reservoir gas composition, and (3) the injected CO2 volumes. The selected reservoir is typical of gas-condensate reservoirs in Northern Croatia (and more generally in Drava Basin), as it contains about 50% CO2 (mole). Reservoir simulations of history-matched model showed base case (production without injection) and several cases of CO2 enhanced gas recovery, but with a focus on CO2 storage rather than maximizing hydrocarbon gas production achieved by converting a production well to a CO2 injection well. General findings are that even in gas reservoirs with such extreme initial CO2 content, gas production with CO2 injection can be carbon-negative. In almost all simulated CO2 injection scenarios, the process is carbon-negative from the time of CO2 injection, and in scenarios where CO2 injection begins earlier, it is carbon-negative from the start of gas production, which opens up the possibility of cost-effective storage of CO2 while producing natural gas with net negative CO2 emissions.

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.

CO2 storage in saline formation: the impacts of reservoir properties and geometry on CO2 trapping mechanisms

2009 ◽  
Vol 49 (1) ◽  
pp. 405
Author(s):  
Diane Labregere ◽  
Norhafiz Marmin ◽  
Suzanne Hurter ◽  
Johan Berge ◽  
Alexander A. Lukyanov
Keyword(s):  
Site Selection ◽  
Co2 Storage ◽  
Separation Distance ◽  
Sensitivity Analyses ◽  
Co2 Injection ◽  
Storage Site ◽  
Residual Saturation ◽  
Worst Case ◽  
Study Results ◽  
Co2 Plume

Effective geological storage of CO2 can be accomplished through a number of trapping mechanisms. Physical trapping is achieved through either CO2 being trapped under a structural closure or CO2 made immobile in the pore space, as residual saturation, by capillary action. Geochemical trapping, which might be regarded as a more secure mode of storage, is achieved through dissolution of CO2 in formation water and precipitation of carbonates. The dissolution rate depends on surface contact and is generally enhanced by greater CO2 plume movement. During site selection, a potential injection well location is commonly evaluated with respect to the proximity to potential leakage features. This paper investigates requirements for separation distance between CO2 injection location and potential leakage features in highly permeable steeply dipping brine reservoir settings. Reservoir models are simulated with a compositional code and sensitivity analyses performed with variations in reservoir permeability, hysteresis effects, and formation dip. Trapping mechanisms, over a timescale of several centuries, are illustrated as key indicators for containment and storage performance. Study results suggest that the amount of CO2 trapped by dissolution and residual saturation is enhanced by a dynamically flowing plume. The simulation results demonstrate that the separation distance requirement typically envisaged in a worst-case reservoir geometry setting is commonly overly conservative, representing opportunity for further optimisation. Numerical simulation is useful in addressing the complex reality of flow dynamics such as hysteresis in footprint prediction. Understanding CO2 plume migration scenarios relative to potential leakage risks, under various key reservoir key properties, is essential in storage containment and capacity assessments for storage site selection and development.

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.

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1058-1068 ◽  
Author(s):  
P.. Bolourinejad ◽  
R.. Herber
Keyword(s):  
The Netherlands ◽  
Carbonic Acid ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Geological Time ◽  
Core Samples ◽  
Carbon Dioxide Co2 ◽  
Gas Fields

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

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