scholarly journals Sensitivity Analysis of Geomechanical Constraints in CO2 Storage to Screen Potential Sites in Deep Saline Aquifers

2021 ◽  
Vol 3 ◽  
Author(s):  
Yashvardhan Verma ◽  
Vikram Vishal ◽  
P. G. Ranjith
Keyword(s):  
Sensitivity Analysis ◽  
Pore Pressure ◽  
Co2 Storage ◽  
Pressure Rise ◽  
Injection Rate ◽  
Early Years ◽  
Rock Properties ◽  
Deep Aquifers ◽  
Plume Migration ◽  
Storage Potential

In order to tackle the exponential rise in global CO2 emissions, the Intergovernmental Panel on Climate Change (IPCC) proposed a carbon budget of 2,900 Gt to limit the rise in global temperature levels to 2°C above the pre-industrial level. Apart from curbing our emissions, carbon sequestration can play a significant role in meeting these ambitious goals. More than 500 Gt of CO2 will need to be stored underground by the end of this century to make a meaningful impact. Global capacity for CO2 storage far exceeds this requirement, the majority of which resides in unexplored deep aquifers. To identify potential storage sites and quantify their storage capacities, prospective aquifers or reservoirs need to be screened based on properties that affect the retention of CO2 in porous rocks. Apart from the total volume of a reservoir, the storage potential is largely constrained by an increase in pore pressure during the early years of injection and by migration of the CO2 plume in the long term. The reservoir properties affect both the pressure buildup and the plume front below the caprock. However, not many studies have quantified these effects. The current analysis computes the effect of rock properties (porosity, permeability, permeability anisotropy, pore compressibility, and formation water salinity) and injection rate on both these parameters by simulating CO2 injection at the bottom of a 2D mesh grid with hydrostatic boundary conditions. The study found that the most significant property in the sensitivity analysis was permeability. Porosity too affected the CO2 plume migration substantially, with higher porosities considerably delaying horizontal and vertical migration. Injection rate impacted both the pressure rise and plume migration consistently. Thus, in screening potential storage sites, we can infer that permeability is the dominant criterion when the pore pressure is closer to the minimum principal stress in the rocks, due to which injection rate needs to be managed with greater caution. Porosity is more significant when the lateral extents of the reservoir limit the storage potential.

Effect of brine salinity on CO2 plume migration and trapping capacity in deep saline aquifers

2017 ◽  
Vol 57 (1) ◽  
pp. 100 ◽  
Author(s):  
Emad A. Al-Khdheeawi ◽  
Stephanie Vialle ◽  
Ahmed Barifcani ◽  
Mohammad Sarmadivaleh ◽  
Stefan Iglauer
Keyword(s):  
Co2 Storage ◽  
Three Dimensional ◽  
Rock Properties ◽  
Saline Aquifers ◽  
Migration Distance ◽  
Deep Saline Aquifer ◽  
Plume Migration ◽  
Co2 Plume ◽  
Wet Rocks ◽  
Brine Salinity

CO2 migration and storage capacity are highly affected by various parameters (e.g. reservoir temperature, vertical to horizontal permeability ratio, cap rock properties, aquifer depth and the reservoir heterogeneity). One of these parameters, which has received little attention, is brine salinity. Although brine salinity has been well demonstrated previously as a factor affecting rock wettability (i.e. higher brine salinity leads to more CO2-wet rocks), its effect on the CO2 storage process has not been addressed effectively. Thus, we developed a three-dimensional homogeneous reservoir model to simulate the behaviour of a CO2 plume in a deep saline aquifer using five different salinities (ranging from 2000 to 200 000 ppm) and have predicted associated CO2 migration patterns and trapping capacities. CO2 was injected at a depth of 1408 m for a period of 1 year at a rate of 1 Mt year–1 and then stored for the next 100 years. The results clearly indicate that 100 years after the injection of CO2 has stopped, the salinity has a significant effect on the CO2 migration distance and the amount of mobile, residual and dissolved CO2. First, the results show that higher brine salinity leads to an increase in CO2 mobility and CO2 migration distance, but reduces the amount of residually trapped CO2. Furthermore, high brine salinity leads to reduced dissolution trapping. Thus, we conclude that less-saline aquifers are preferable CO2 sinks.

Long-term Pressure Evolutions due to Geologic Heterogeneities during CO2 Injection

2020 ◽  
Author(s):  
Taehee Kim
Keyword(s):  
Pore Pressure ◽  
Co2 Storage ◽  
Sedimentary Environment ◽  
Pressure Rise ◽  
Injection Well ◽  
Design Stage ◽  
Co2 Injection ◽  
Statistical Parameters ◽  
Additional Increase

<p>In general, the characterization of the heterogeneity in a reservoir is considered to be important in the exploration and selection of CO2 storage formation, but it is not clear how the heterogeneity affects the evolution of the pore pressure. In particular, long-term changes in the pore pressure when most of the storage candidates are bounded by faults or bedrock, such as Korea, have been rarely examined. Many literature related to results of studies and international CCS standardization indicate that the heterogeneity of storage formation should be identified, but it is still unclear to what extent the precision or resolution of the investigation is required at the selection or design stage. The heterogeneity of sedimentary layers can be divided into two categories in terms of geographic statistics. At this time, the criteria of the classification is statistical stationarity. From a geological point of view, the statistical stationarity may be consistent with the sedimentary environment. In other words, it can be assumed that strata deposited at the same place, at similar times, and in similar circumstances have similar hydrogeological properties, despite of some detailed differences. In this case, the heterogeneity refers to “detailed differences” and the homogeneity refers to statistical parameters such as means or variances of physical properties and spatial auto-covariance. On the other hand, the nonstationary heterogeneity refers to a case where there is no statistical homogeneity, due to differences in geological structures such as faults and differences in strata such as sandstone and mudstone. In this study, the numerical sensitivity analysis was used to investigate the effect of each heterogeneity on the pressure buildup. The nonstationary heterogeneity applied in this study is a vertical structure that completely penetrates the storage formation. The results of ten models with the stationary heterogeneity showed almost similar pressure changes in the macroscale, although there were some pore pressure differences at the injection well between each of models. The pressure difference at the injection well between each model was dependent on the bulk permeability within a certain distance (200m in this study) near the injection wells, not on the average permeability of the whole system. In other words, when the injection well is installed at a point having a relatively high permeability, some additional increase in pressure due to the heterogeneity rarely occurs. However, lowering the permeability due to nonstationary heterogeneity can causes the global pressure rise in the storage formation, results were very similar to those of the case with closed boundary condition when the heterogeneity reduced the permeability to 10-4 times or less of the permeability in the storage formation.</p>

A shortcut pressure swing adsorption analogue model to estimate Gas-in-Place and CO2 storage potential of gas shales

Fuel ◽  
2021 ◽  
Vol 301 ◽  
pp. 121014
Author(s):  
Humera Ansari ◽  
Elena Rietmann ◽  
Lisa Joss ◽  
JP Martin Trusler ◽  
Geoffrey Maitland ◽  
...  
Keyword(s):  
Pressure Swing Adsorption ◽  
Co2 Storage ◽  
Analogue Model ◽  
Gas Shales ◽  
Storage Potential ◽  
Pressure Swing

A Novel Pore-Scale Thermal-Fracture-Acidizing Model With Heterogeneous Rock Properties

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 280-292 ◽  
Author(s):  
John Lyons ◽  
Hadi Nasrabadi ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Mass Transfer ◽  
Reactive Transport ◽  
Reaction Rate ◽  
Oil And Gas ◽  
Injection Rate ◽  
Rock Properties ◽  
Thermal Fracture ◽  
Pore Scale ◽  
Heterogeneous Rock ◽  
Acid Reaction

Summary Fracture acidizing is a well-stimulation technique used to improve the productivity of low-permeability reservoirs and to bypass deep formation damage. The reaction of injected acid with the rock matrix forms etched channels through which oil and gas can then flow upon production. The properties of these etched channels depend on the acid-injection rate, temperature, reaction chemistry, mass-transport properties, and formation mineralogy. As the acid enters the formation, it increases in temperature by heat exchange with the formation and the heat generated by acid reaction with the rock. Thus, the reaction rate, viscosity, and mass transfer of acid inside the fracture also increase. In this study, a new thermal-fracture-acidizing model is presented that uses the lattice Boltzmann method to simulate reactive transport. This method incorporates both accurate hydrodynamics and reaction kinetics at the solid/liquid interface. The temperature update is performed by use of a finite-difference technique. Furthermore, heterogeneity in rock properties (e.g., porosity, permeability, and reaction rate) is included. The result is a model that can accurately simulate realistic fracture geometries and rock properties at the pore scale and that can predict the geometry of the fracture after acidizing. Three thermal-fracture-acidizing simulations are presented here, involving injection of 15 and 28 wt% of hydrochloric acid into a calcite fracture. The results clearly show an increase in the overall fracture dissolution because of the addition of temperature effects (increasing the acid-reaction and mass-transfer rates). It has also been found that by introducing mineral heterogeneity, preferential dissolution leads to the creation of uneven etching across the fracture surfaces, indicating channel formation.

scholarly journals The investigation of CO2 storage potential in the Algoa basin in South Africa

2014 ◽  
Vol 63 ◽  
pp. 2800-2810 ◽  
Author(s):  
Nontobeko Chabangu ◽  
Brendan Beck ◽  
Nigel Hicks ◽  
Jurie Viljoen ◽  
Sean Davids ◽  
...  
Keyword(s):  
South Africa ◽  
Co2 Storage ◽  
Storage Potential

Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field

2021 ◽  
Author(s):  
Mohammed Ahmed Al-Janabi ◽  
Omar F. Al-Fatlawi ◽  
Dhifaf J. Sadiq ◽  
Haider Abdulmuhsin Mahmood ◽  
Mustafa Alaulddin Al-Juboori
Keyword(s):  
Genetic Algorithm ◽  
Sensitivity Analysis ◽  
Middle Eastern ◽  
Optimization Technique ◽  
Injection Rate ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Artificial Lift ◽  
Gas Lift

Abstract Artificial lift techniques are a highly effective solution to aid the deterioration of the production especially for mature oil fields, gas lift is one of the oldest and most applied artificial lift methods especially for large oil fields, the gas that is required for injection is quite scarce and expensive resource, optimally allocating the injection rate in each well is a high importance task and not easily applicable. Conventional methods faced some major problems in solving this problem in a network with large number of wells, multi-constrains, multi-objectives, and limited amount of gas. This paper focuses on utilizing the Genetic Algorithm (GA) as a gas lift optimization algorithm to tackle the challenging task of optimally allocating the gas lift injection rate through numerical modeling and simulation studies to maximize the oil production of a Middle Eastern oil field with 20 production wells with limited amount of gas to be injected. The key objective of this study is to assess the performance of the wells of the field after applying gas lift as an artificial lift method and applying the genetic algorithm as an optimization algorithm while comparing the results of the network to the case of artificially lifted wells by utilizing ESP pumps to the network and to have a more accurate view on the practicability of applying the gas lift optimization technique. The comparison is based on different measures and sensitivity studies, reservoir pressure, and water cut sensitivity analysis are applied to allow the assessment of the performance of the wells in the network throughout the life of the field. To have a full and insight view an economic study and comparison was applied in this study to estimate the benefits of applying the gas lift method and the GA optimization technique while comparing the results to the case of the ESP pumps and the case of naturally flowing wells. The gas lift technique proved to have the ability to enhance the production of the oil field and the optimization process showed quite an enhancement in the task of maximizing the oil production rate while using the same amount of gas to be injected in the each well, the sensitivity analysis showed that the gas lift method is comparable to the other artificial lift method and it have an upper hand in handling the reservoir pressure reduction, and economically CAPEX of the gas lift were calculated to be able to assess the time to reach a profitable income by comparing the results of OPEX of gas lift the technique showed a profitable income higher than the cases of naturally flowing wells and the ESP pumps lifted wells. Additionally, the paper illustrated the genetic algorithm (GA) optimization model in a way that allowed it to be followed as a guide for the task of optimizing the gas injection rate for a network with a large number of wells and limited amount of gas to be injected.

Pore Pressure Rise During Cyclic Loading of Sands

1982 ◽  
Vol 108 (2) ◽  
pp. 315-319
Author(s):  
Christos P. Tsatsanifos ◽  
Sarada K. Sarma
Keyword(s):  
Cyclic Loading ◽  
Pore Pressure ◽  
Pressure Rise
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