scholarly journals Change in Convection Mixing Properties with Salinity and Temperature: CO2 Storage Application

Polymers ◽  
2020 ◽  
Vol 12 (9) ◽  
pp. 2084
Author(s):  
Lanlan Jiang ◽  
Sijia Wang ◽  
Donglei Liu ◽  
Weixin Zhang ◽  
Guohuan Lu ◽  
...  
Keyword(s):  
Mass Transfer ◽  
Co2 Storage ◽  
Onset Time ◽  
Effect Of Temperature ◽  
Storage Site ◽  
Charge Coupled Device ◽  
Mixing Properties ◽  
Formation Number ◽  
And Migration ◽  
Convection Dominated

In this study, we visualised CO2-brine, density-driven convection in a Hele-Shaw cell. Several experiments were conducted to analyse the effects of the salinity and temperature. The salinity and temperature of fluids were selected according to the storage site. By using charge coupled device (CCD) technology, convection finger formation and development were obtained through direct imaging and processing. The process can be divided into three stages: diffusion-dominated, convection-dominated and shutdown stages. Fingers were formed along the boundary at the onset time, reflecting the startup of convection mixing. Fingers formed, moved and aggregated with adjacent fingers during the convection-dominated stage. The relative migration of brine-saturated CO2 and brine enhanced the mass transfer. The effects of salinity and temperature on finger formation, number, and migration were analysed. Increasing the salinity accelerated finger formation but suppressed finger movement, and the onset time was inversely related to the salinity. However, the effect of temperature on convection is complex. The dissolved CO2 mass was investigated by calculating the CO2 mass fraction in brine during convection mixing. The results show that convection mixing greatly enhanced mass transfer. The study has implications for predicting the CO2 dissolution trapping time and accumulation for the geological storage of CO2.

Applied Risk and Consequence Analysis for CO2 Storage Projects – the Captain X Storage Site, Offshore UK (Acorn)

2019 ◽  
Author(s):  
Niklas Heinemann ◽  
Hazel Robertson ◽  
Juan Alcalde ◽  
Alan James ◽  
Saeed Ghanbari ◽  
...  
Keyword(s):  
Co2 Storage ◽  
Storage Site ◽  
Consequence Analysis

Towards a Multiphysical Model and Inversion of the Ketzin CO2 Storage Site Full Operational Period

2019 ◽  
Author(s):  
Bernd Wiese ◽  
Wolfgang Weinzierl ◽  
Cornelia Schmidt-Hattenberger
Keyword(s):  
Co2 Storage ◽  
Storage Site ◽  
And Inversion

Fracture mapping using seismic amplitude variation with offset and azimuth analysis at the Weyburn CO2 storage site

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. B295-B306 ◽  
Author(s):  
Alexander Duxbury ◽  
Don White ◽  
Claire Samson ◽  
Stephen A. Hall ◽  
James Wookey ◽  
...  
Keyword(s):  
Cross Sections ◽  
Co2 Storage ◽  
Horizontal Stress ◽  
Storage Site ◽  
Fracture Zones ◽  
Amplitude Variation ◽  
Amplitude Variation With Offset ◽  
Seal Integrity ◽  
Cap Rock ◽  
Weyburn Field

Cap rock integrity is an essential characteristic of any reservoir to be used for long-term [Formula: see text] storage. Seismic AVOA (amplitude variation with offset and azimuth) techniques have been applied to map HTI anisotropy near the cap rock of the Weyburn field in southeast Saskatchewan, Canada, with the purpose of identifying potential fracture zones that may compromise seal integrity. This analysis, supported by modeling, observes the top of the regional seal (Watrous Formation) to have low levels of HTI anisotropy, whereas the reservoir cap rock (composite Midale Evaporite and Ratcliffe Beds) contains isolated areas of high intensity anisotropy, which may be fracture-related. Properties of the fracture fill and hydraulic conductivity within the inferred fracture zones are not constrained using this technique. The predominant orientations of the observed anisotropy are parallel and normal to the direction of maximum horizontal stress (northeast–southwest) and agree closely with previous fracture studies on core samples from the reservoir. Anisotropy anomalies are observed to correlate spatially with salt dissolution structures in the cap rock and overlying horizons as interpreted from 3D seismic cross sections.

Assessing the Accuracy of Fault Interpretation using Machine Learning Techniques when Risking Faults for CO2 Storage Site Assessment

2021 ◽  
pp. 1-55
Author(s):  
Emma A. H. Michie ◽  
Behzad Alaei ◽  
Alvar Braathen
Keyword(s):  
Deep Learning ◽  
New Technologies ◽  
Co2 Storage ◽  
Fault Reactivation ◽  
Machine Learning Techniques ◽  
Close Similarity ◽  
Storage Site ◽  
Site Assessment ◽  
Learning Techniques ◽  
Fault Interpretation

Generating an accurate model of the subsurface for the purpose of assessing the feasibility of a CO2 storage site is crucial. In particular, how faults are interpreted is likely to influence the predicted capacity and integrity of the reservoir; whether this is through identifying high risk areas along the fault, where fluid is likely to flow across the fault, or by assessing the reactivation potential of the fault with increased pressure, causing fluid to flow up the fault. New technologies allow users to interpret faults effortlessly, and in much quicker time, utilizing methods such as Deep Learning. These Deep Learning techniques use knowledge from Neural Networks to allow end-users to compute areas where faults are likely to occur. Although these new technologies may be attractive due to reduced interpretation time, it is important to understand the inherent uncertainties in their ability to predict accurate fault geometries. Here, we compare Deep Learning fault interpretation versus manual fault interpretation, and can see distinct differences to those faults where significant ambiguity exists due to poor seismic resolution at the fault; we observe an increased irregularity when Deep Learning methods are used over conventional manual interpretation. This can result in significant differences between the resulting analyses, such as fault reactivation potential. Conversely, we observe that well-imaged faults show a close similarity between the resulting fault surfaces when both Deep Learning and manual fault interpretation methods are employed, and hence we also observe a close similarity between any attributes and fault analyses made.

Understanding the Flow Dynamics of CO2 Plumes in the Subsurface

2021 ◽  
Author(s):  
Florence Letitia Bebb ◽  
Kate Clare Serena Evans ◽  
Jagannath Mukherjee ◽  
Bilal Saeed ◽  
Geovani Christopher
Keyword(s):  
Carbon Capture ◽  
Oil And Gas ◽  
Co2 Storage ◽  
Flow Dynamics ◽  
Hydrocarbon Exploration ◽  
Hydrocarbon Reservoir ◽  
Exploration And Production ◽  
And Migration ◽  
Carbon Dioxide Co2 ◽  
Hydrocarbon Exploration And Production

Abstract There are several significant differences between the behavior of injected CO2 and reservoired hydrocarbons in the subsurface. These fundamental differences greatly influence the modeling of CO2 plumes. Carbon capture, utilization, and storage (CCUS) is growing in importance in the exploration and production (E&P) regulatory environment with the Oil and Gas Climate Initiative (OGCI) making CCUS a priority. Companies need to prospect for storage sites and evaluate both the short-term risks and long-term fate of stored carbon dioxide (CO2). Understanding the physics governing fluid flow is important to both CO2 storage and hydrocarbon exploration and production. In the last decade, there has been much research into the movement and migration of CO2 in the subsurface. A better understanding of the flow dynamics of CO2 plumes in the subsurface has highlighted a number of significant differences in modeling CO2 storage sites compared with hydrocarbon reservoir simulations. These differences can greatly influence reliability when modeling CO2 storage sites.

Making Things Right in Development and Management of Highly Contaminated Giant Carbonate Gas Field and Returning the CO2 to Subsurface Sequestration

2021 ◽  
Author(s):  
Raj Deo Tewari ◽  
Mohd Faizal Sedaralit
Keyword(s):  
Co2 Storage ◽  
Geological Structure ◽  
Geochemical Data ◽  
Gas Field ◽  
Reservoir Architecture ◽  
Target Field ◽  
Hydrocarbon Gas ◽  
Separation Of Co2 ◽  
And Migration ◽  
And Storage

Abstract Natural gas is the noble fuel of 21st century. Consumption increased nearly 30% in last decade. Exploitation of conventional, unconventional, and contaminated gas resources are in focus to meet the demand. There are number of giant gas fields discovered worldwide and some of them with higher degree of contaminants viz. CO2, H2S and Hg. Additionally, they have operating challenges of high pressure and temperature. It becomes more complex when discovery is in offshore environment. This study presents the development and production, separation, transportation and identification & evaluation of storage sites and sequestration and MMV plan of a giant carbonate gas field in offshore Malaysia. Geological, Geophysical and petrophysical data used to describe the reservoir architecture, property distribution and spatial variation in more than 1000m thick gas bearing formation. Laboratory studies carried out to generate the rock and fluid representative SCAL (G-W), EOS and Supercritical CO2-brine relative permeability, geomechanics and geochemical data for recovery and storage estimates in simulation model and evaluating the post storage scenario. These data are critical in hydrocarbon gas prediction and firming up the number of development wells and in the simulation of CO2 storage depleted carbonate gas field. Important is to understand the mechanism in the target field for storage capacity, types of storage- structural and stratigraphic trapping, solubility trapping, residual trapping and mineral trapping. Study covers methodologies developed for minimization of hydrocarbon loss during contaminants separation and utilization of CO2 in usable products. Uncertainty and risk analysis have been carried out to have range of solution for production prediction and CO2 storage. Coupled Simulation studies predict the production plateau rate and 5 Tscf recovery separated contaminants profile and volume > one Tscf in order to have suitable geological structure for storage safely forever. Major uncertainties in the dynamic and coupled geomechanical-geochemical dynamic model has been captured and P90, P50, P10 forecast and storage rates and volumes have been calculated. Results includes advance methodologies of separation of hydrocarbon gas and CO2 like membrane and cryogenics for bulk separation of CO2 from raw gas and its transportation in liquid and supercritical form for storage. Study estimates components of sequestration mechanism, effect of heterogeneity on transport in porous media and height of stored CO2 in depleted reservoir and migration of plume vertically and horizontally. Generation of chemical product using separated CO2 for industrial use is highlighted.

How Chosen Seismic Fault Picking Strategy Influences Subsequent Fault Analyses: A Case Study from the Horda Platform, with Implications for CO2 storage

2021 ◽  
Author(s):  
Emma Michie ◽  
Mark Mulrooney ◽  
Alvar Braathen
Keyword(s):  
Fluid Flow ◽  
Co2 Storage ◽  
Fault Analysis ◽  
Surface Generation ◽  
Storage Site ◽  
Seismic Line ◽  
Fault Stability ◽  
Line Spacing ◽  
Fault Growth

<p>Significant uncertainties occur through varying methodologies when interpreting faults using seismic data.  These uncertainties are carried through to the interpretation of how faults may act as baffles/barriers or increase fluid flow.  Seismic line spacing chosen by the interpreter when picking fault segments, as well as the chosen surface generation algorithm used, will dictate how detailed or smoothed the surface is, and hence will impact any further interpretation such as fault seal, fault stability and fault growth analyses.</p><p>This contribution is a case study showing how picking strategies influence analysis of a bounding fault in terms of CO<sub>2</sub> storage assessment.  This example utilizes data from the Smeaheia potential storage site within the Horda Platform, 20 km East of Troll East.  This is a fault bound prospect, known as the Alpha prospect, and hence the bounding fault is required to have a high seal potential and low chance of reactivation upon CO<sub>2</sub> injection.</p><p>We can observe that an optimum spacing for fault interpretation for this case study is set at approximately 100 m.  It appears that any additional detail through interpretation with a line spacing of ≤50 m simply adds further complexities, associated with sensitivities by the individual interpreter.  Hence, interpreting at a finer scale may not necessarily improve the subsurface model and any related analysis, but in fact lead to the production of highly irregular surfaces, which impacts any further fault analysis.  Interpreting on spacing greater than 100 m often leads to overly smoothed fault surfaces that miss details that could be crucial, both for fault seal / stability as well as for fault growth models.</p><p>Uncertainty associated with the chosen seismic interpretation methodology will follow through to subsequent fault seal analysis, such as analysis of whether in situ stresses, combined with increased pore pressure through CO<sub>2</sub> injection, will act to reactivate the faults, leading to up-fault fluid flow / seep.  We have shown that changing picking strategies significantly alters the interpreted stability of the fault, where picking with an increased line spacing has shown to increase the overall fault stability, and picking using every line leads to the interpretation of a critically stressed fault.  Alternatively, it is important to note that differences in picking strategy show little influence on the overall predicted fault membrane seal (i.e. shale gouge ratio) of the fault, used when interpreting the fault seal capacity for a fault bound CO<sub>2</sub> storage site.</p>

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