Experimental Investigations of CO2 Solubility and Variations in Petrophysical Properties due to CO2 Storage in Carbonate Reservoir Rocks

2013 ◽  
Author(s):  
Shedid A Shedid ◽  
Adel M. Salem
Keyword(s):  
Co2 Storage ◽  
Carbonate Reservoir ◽  
Experimental Investigations ◽  
Petrophysical Properties ◽  
Co2 Solubility ◽  
Reservoir Rocks

An Experimental and Simulation Study of CO2 Sequestration in an Underground Formations; Impact on Geomechanical and Petrophysical Properties

2021 ◽  
Author(s):  
Sobia Fatima ◽  
Hafiz Muhammad Mutahhar Khan ◽  
Zeeshan Tariq ◽  
Mohammad Abdalla ◽  
Mohamed Mahmoud
Keyword(s):  
Simulation Model ◽  
Reaction Kinetics ◽  
Co2 Sequestration ◽  
Laboratory Experiments ◽  
Co2 Storage ◽  
Storage Period ◽  
Simulation Software ◽  
Carbonate Reservoir ◽  
Petrophysical Properties ◽  
Porosity And Permeability

Abstract Carbon dioxide (CO2) sequestration is a technique to store CO2 into an underground formation. CO2 can cause a severe reaction with the underground formation and injection tubing inside the well. Successful CO2 storage into underground formations depends on many factors such as efficient sealing, no escaping from the storage, and minimum corrosion to injection tubing/casing. Therefore, proper planning involving thorough study and reaction kinetics of CO2 with the underground formation is indeed necessary for proper planning. The main aim and objective of this study are to investigate the effect of CO2 storage with different cap rocks such as tight carbonate and shale under simulated reservoir conditions. The samples were stored for different times such as 10, 20, and 120 days. The objectives of the study were achieved by carrying out extensive laboratory experiments before and after sequestration. The laboratory experiments included were rock compressive and tensile strength tests, petrophysical tests, and rock mechanical tests. The laboratory results were later used to investigate the reaction kinetics study of CO2 with the underground formation using CMG simulation software. The effect of injection rate, the point of injection, purity of the injection fluid, reservoir heterogeneity, reservoir depth, and minimum miscibility pressure was analyzed. In this simulation model, CO2 is injected for 25 years using CMG-GEM simulation software and then the fate of CO2 post injection is modeled for the next 225 years. The simulation results showed a notable effect on the mechanical strength and petrophysical parameters of the rock after sequestration, also the solubility of CO2 decreases with the increase in salinity and injection pressure. The results also showed that the storage of CO2 increases the petrophysical properties of porosity and permeability of the formation rock when the storage period is more than 20 days because of calcite precipitation and CO2 dissolution. A storage period of fewer than 20 days does not show any significant effect on the porosity and permeability of carbonate reservoir rock. A sensitivity analysis was carried out which showed that the rate of CO2 sequestration is sensitive to the mineral-water reaction kinetic constants. The sensitivity of CO2 sequestration to the rate constants decreases in magnitude respectively for different clay minerals. The new simulation model considers the effect of reaction kinetics and geomechanical parameters. The new model is capable of predicting the compatibility of CO2 sequestration for a particular field for a particular time.

Seismic-derived geomechanical properties of potential CO2 storage reservoir and cap rock in Smeaheia area, northern North Sea

2021 ◽  
Vol 40 (4) ◽  
pp. 254-260
Author(s):  
Manzar Fawad ◽  
Md Jamilur Rahman ◽  
Nazmul Haque Mondol
Keyword(s):  
Elastic Property ◽  
North Sea ◽  
Co2 Storage ◽  
Velocity Ratio ◽  
Flow Simulation ◽  
Storage Site ◽  
Petrophysical Properties ◽  
Geomechanical Properties ◽  
Reservoir Rocks ◽  
Northern North Sea

Geologic CO2 storage site selection requires reservoir, seal, and overburden investigation to prevent injection- and storage-related risks. Three-dimensional geomechanical modeling and flow simulation are crucial to evaluate these mechanical-failure-related consequences; however, the model input parameters are limited and challenging to estimate. This study focuses on geomechanical properties extracted from seismic-derived elastic property cubes. The studied reservoirs (Middle Jurassic Sognefjord, Fensfjord, and Krossfjord formation sandstones) and cap rocks (Heather and Draupne formation shales) are located in the Smeaheia area, northern North Sea, and are evaluated for a potential CO2 storage site. From the elastic property cubes, i.e., acoustic impedance, P- to S-wave velocity ratio, and bulk density, we obtained geomechanical property cubes of Young's modulus, Poisson's ratio, shear modulus, lambda-rho, and mu-rho. Petrophysical property cubes such as porosity and shale volume were also available and were extracted from the elastic property cubes using deterministic methods. We evaluated the geomechanical properties to observe their relationship with depth, compaction/cementation, and petrophysical properties to characterize the cap and reservoir rocks. We found good coherence between the geomechanical and petrophysical properties and their relationship with compaction as a function of depth. The brittleness analyses using elastic property crossplots reveal that both the cap and reservoir rocks are mainly ductile to less ductile, posing lower fracturing risk during CO2 injection. This also indicates lower risks of associated microseismic and possible CO2 leakage.

Late Permian carbonate concretions in the marine siliciclastic sediments of the Ravnefjeld Formation, East Greenland

2002 ◽  
pp. 126-132
Author(s):  
Jesper Kresten Nielsen ◽  
Nils-Martin Hanken
Keyword(s):  
Mineral Resources ◽  
Sedimentary Basins ◽  
Sedimentary Facies ◽  
Carbonate Reservoir ◽  
Upper Permian ◽  
Late Permian ◽  
East Greenland ◽  
Reservoir Rocks ◽  
Carbonate Concretions ◽  
Siliciclastic Sediments

NOTE: This article was published in a former series of GEUS Bulletin. Please use the original series name when citing this article, for example: Kresten Nielsen, J., & Hanken, N.-M. (2002). Late Permian carbonate concretions in the marine siliciclastic sediments of the Ravnefjeld Formation, East Greenland. Geology of Greenland Survey Bulletin, 191, 126-132. https://doi.org/10.34194/ggub.v191.5140 _______________ This investigation of carbonate concretions from the Late Permian Ravnefjeld Formation in East Greenland forms part of the multi-disciplinary research project Resources of the sedimentary basins of North and East Greenland (TUPOLAR; Stemmerik et al. 1996, 1999). The TUPOLAR project focuses on investigations and evaluation of potential hydrocarbon and mineral resources of the Upper Permian – Mesozoic sedimentary basins. In this context, the Upper Permian Ravnefjeld Formation occupies a pivotal position because it contains local mineralisations and has source rock potential for hydrocarbons adjacent to potential carbonate reservoir rocks of the partly time-equivalent Wegener Halvø Formation (Harpøth et al. 1986; Surlyk et al. 1986; Stemmerik et al. 1998; Pedersen & Stendal 2000). A better understanding of the sedimentary facies and diagenesis of the Ravnefjeld Formation is therefore crucial for an evaluation of the economic potential of East Greenland.

Enhanced and Rock Typing-Based Reservoir Characterization of the Palaeocene Harash Carbonate Reservoir-Zelten Field-Sirte Basin-Libya

2021 ◽  
Author(s):  
Mohamed Masoud ◽  
W. Scott Meddaugh ◽  
Masoud Eljaroshi ◽  
Khaled Elghanduri
Keyword(s):  
Rock Type ◽  
Carbonate Reservoir ◽  
Classification Model ◽  
Reservoir Rocks ◽  
The Core ◽  
Core Samples ◽  
Rock Types ◽  
Rock Typing ◽  
Open Hole ◽  
Type Classification

Abstract The Harash Formation was previously known as the Ruaga A and is considered to be one of the most productive reservoirs in the Zelten field in terms of reservoir quality, areal extent, and hydrocarbon quantity. To date, nearly 70 wells were drilled targeting the Harash reservoir. A few wells initially naturally produced but most had to be stimulated which reflected the field drilling and development plan. The Harash reservoir rock typing identification was essential in understanding the reservoir geology implementation of reservoir development drilling program, the construction of representative reservoir models, hydrocarbons volumetric calculations, and historical pressure-production matching in the flow modelling processes. The objectives of this study are to predict the permeability at un-cored wells and unsampled locations, to classify the reservoir rocks into main rock typing, and to build robust reservoir properties models in which static petrophysical properties and fluid properties are assigned for identified rock type and assessed the existed vertical and lateral heterogeneity within the Palaeocene Harash carbonate reservoir. Initially, an objective-based workflow was developed by generating a training dataset from open hole logs and core samples which were conventionally and specially analyzed of six wells. The developed dataset was used to predict permeability at cored wells through a K-mod model that applies Neural Network Analysis (NNA) and Declustring (DC) algorithms to generate representative permeability and electro-facies. Equal statistical weights were given to log responses without analytical supervision taking into account the significant log response variations. The core data was grouped on petrophysical basis to compute pore throat size aiming at deriving and enlarging the interpretation process from the core to log domain using Indexation and Probabilities of Self-Organized Maps (IPSOM) classification model to develop a reliable representation of rock type classification at the well scale. Permeability and rock typing derived from the open-hole logs and core samples analysis are the main K-mod and IPSOM classification model outputs. The results were propagated to more than 70 un-cored wells. Rock typing techniques were also conducted to classify the Harash reservoir rocks in a consistent manner. Depositional rock typing using a stratigraphic modified Lorenz plot and electro-facies suggest three different rock types that are probably linked to three flow zones. The defined rock types are dominated by specifc reservoir parameters. Electro-facies enables subdivision of the formation into petrophysical groups in which properties were assigned to and were characterized by dynamic behavior and the rock-fluid interaction. Capillary pressure and relative permeability data proved the complexity in rock capillarity. Subsequently, Swc is really rock typing dependent. The use of a consistent representative petrophysical rock type classification led to a significant improvement of geological and flow models.

scholarly journals Experimental Investigations of the Process of Carbonate Fracture Dissolution Enlargement under Reservoir Temperature and Pressure Conditions

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-19
Author(s):  
Jingxia Wang ◽  
Qingchun Yu
Keyword(s):  
Laser Scanning ◽  
Early Stage ◽  
Confining Pressure ◽  
Carbonate Reservoir ◽  
Dissolution Process ◽  
Experimental Investigations ◽  
Polynomial Type ◽  
Calcite Veins ◽  
Before And After ◽  
Logarithmic Type

Karst is a central focus in the field of carbonate reservoir geology. Fracture dissolution enlargement is an important mechanism for the formation of high-quality reservoirs. This study performed four carbonate fracture dissolution enlargement (CFDE) experiments under a confining pressure of 20 MPa, and temperatures ranged from 40 to 60°C. CO2-saturated deionized water was injected into artificial carbonate fractures at approximately 11.5 ml/h for 96, 208, 216, and 216 hours. The water flowing out of the fractures was sampled every 8 h to monitor the concentration of Ca2+. SEM photomicrographs and 3D laser scanning images were taken before and after the CFDE experiments to observe the dissolution process of the fracture surfaces. After the CFDE experiment, the hydraulic apertures (Bh) of sample 1 (S1), sample 3 (S3), and sample 4 (S4) were enlarged by 3.4, 1.4, and 1.2 times, respectively. The aperture of sample 2 (S2) was slightly reduced in the early stage of the experiment. The experimental results of this study demonstrate that Bh can be divided into three categories as a function of time: S type, logarithmic type, and polynomial type. The laboratory dissolution rate of S1, S2, S3, and S4 were 2.50 × 10−6, 3.11 × 10−6, 2.70 × 10−6, and 3.04 × 10−6 mol/m2/s. The pattern of fracture dissolution is closely related to the Peclet and Damkohler numbers. The dissolution processes of high Peclet and Damkohler numbers lead to a pattern of obvious channelization. The Peclet and Damkohler numbers of the S3 CFDE experiment were the highest, and the channelizing dissolution is the most notable in S3 of the four fractures. A dissolution process at low temperature has a higher Peclet number and thus leads to obvious channelizing dissolution. Mineral heterogeneities in the rock also play a significant role in channelizing dissolution. A preferential channel typically develops in places where bioclasts are accumulated or the calcite veins are distributed.

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