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>

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.

scholarly journals Pore Pressure Analysis for Distinguishing Earthquakes Induced by CO2 Injection from Natural Earthquakes

2020 ◽  
Vol 12 (22) ◽  
pp. 9723
Author(s):  
Chanmaly Chhun ◽  
Takeshi Tsuji
Keyword(s):  
Pore Pressure ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Storage Site ◽  
Seasonal Fluctuations ◽  
Induced Earthquakes ◽  
Seismogenic Fault ◽  
Seismogenic Faults ◽  
Natural Earthquakes

It is important to distinguish between natural earthquakes and those induced by CO2 injection at carbon capture and storage sites. For example, the 2004 Mw 6.8 Chuetsu earthquake occurred close to the Nagaoka CO2 storage site during gas injection, but we could not quantify whether the earthquake was due to CO2 injection or not. Here, changes in pore pressure during CO2 injection at the Nagaoka site were simulated and compared with estimated natural seasonal fluctuations in pore pressure due to rainfall and snowmelt, as well as estimated pore pressure increases related to remote earthquakes. Changes in pore pressure due to CO2 injection were clearly distinguished from those due to rainfall and snowmelt. The simulated local increase in pore pressure at the seismogenic fault area was much less than the seasonal fluctuations related to precipitation and increases caused by remote earthquakes, and the lateral extent of pore pressure increase was insufficient to influence seismogenic faults. We also demonstrated that pore pressure changes due to distant earthquakes are capable of triggering slip on seismogenic faults. The approach we developed could be used to distinguish natural from injection-induced earthquakes and will be useful for that purpose at other CO2 sequestration sites.

scholarly journals Snøhvit CO2 Storage Project: Assessment of CO2 Injection Performance Through History Matching of the Injection Well Pressure Over a 32-months Period

2013 ◽  
Vol 37 ◽  
pp. 3267-3274 ◽  
Author(s):  
Ji-Quan Shi ◽  
Claire Imrie ◽  
Caglar Sinayuc ◽  
Sevket Durucan ◽  
Anna Korre ◽  
...  
Keyword(s):  
History Matching ◽  
Co2 Storage ◽  
Injection Well ◽  
Co2 Injection ◽  
Project Assessment

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.

Reservoir Characterization for Uncertainty Analysis and Its Impact on CO2 Injection and Sequestration in a Depleted Offshore Carbonate Gas Field

2021 ◽  
Author(s):  
Debasis P. Das ◽  
Parimal A. Patil ◽  
Pankaj K. Tiwari ◽  
Renato J Leite ◽  
Raj Deo Tewari
Keyword(s):  
Co2 Storage ◽  
Assessment Process ◽  
Rock Properties ◽  
Co2 Injection ◽  
Storage Site ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Well Integrity ◽  
Seismic Anomalies

Abstract The emerging global climate change policies have necessitated the strategic need for prudent management of produced contaminants and, with cold flaring being no more the best option, Carbon Capture Utilization & Storage (CCUS) technology provides opportunity for development of high CO2 contaminant fields. A typical CO2 sequestration project comprises capturing CO2 by separating from produced hydrocarbons followed by injection of CO2 into deep geological formations for long term storage. While injection ofCO2 may continue over tens of years, the long-term containment needs to be ascertained for thousands of years. Several geological and geophysical factors along with the existingwells need to be evaluated to assess the potential risks for CO2 leakage that maychallenge the long-term containment. This study considers a depleted carbonate field located offshore Sarawak as a possible long-term CO2 storage site. Elements that may lead to possible leakage of CO2over time are the existing faults or fractures, development of new fractures/faults during injection, caprock failure due to pressures exceeding fracture pressure during/after injection and possible leakage through existing wells. The risk assessment process includes identification and mapping of faults and fracture networks, mapping of seals, evaluation of seismic anomalies and gas while drilling records, pore-pressure analysis, laboratory experiments for analyzing changes in geomechanical & geochemical rock properties and well integrity of existing wells. All these parameters are cross correlated, and qualitative risk categorization is carried out to determine the robustness of the reservoir for long term CO2 storage. The evaluation of available data indicates less frequent faulting occur only towards the flank with no seismic anomalies associated with them. Some seismic anomalies are observed at shallower levels, however their impact on the reservoir and overburden integrity is assessed to be minimum. There are four shale dominated formations mapped in the overburden section, which will act as potential seals. Estimated fracture pressures for the potential seals ranges between 6200-9280 psia for the deepest seal to 2910-4290 psia for the shallowest. Therefore,it is interpreted that if the post injection reservoir pressure is kept below the initial reservoir pressure of 4480 psia, it would not hold any threat to the caprock integrity.Leakage rate riskalong the existing wells was determined based on well log data. Well integrity check of legacywells helped identify two abandoned wells for rigorous remediation to restore their integrity. The subsurface risk analysis is critical to ascertain the long-term containment of injectedCO2. The integrated subsurface characterization and well integrity analysis approach adopted in this work can be applied to any other field/reservoir to validate its robustness for long-term CO2 injection and storage.

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.

An Application of Probabilistic Risk Assessment PRA Methodology in the Optimization of CO2 Injection Well Locations for CO2 Storage Development Plan, Offshore Malaysia

2021 ◽  
Author(s):  
Ana Widyanita ◽  
Zhong Cai ◽  
Mohd Khaidhir Abdul Hamid ◽  
Ernest A Jones
Keyword(s):  
Risk Assessment ◽  
Risk Evaluation ◽  
Co2 Storage ◽  
Probabilistic Risk Assessment ◽  
Development Plan ◽  
Injection Well ◽  
Co2 Injection ◽  
Individual Element ◽  
Composite Risk ◽  
Probabilistic Risk

Abstract A depleted gas field in the Sarawak basin, offshore Malaysia, was selected as a candidate geological site for CO2 storage. The selection and design for the CO2 injection well locations are an important decision making in the business planning, which involved a complicated risk assessment system covering subsurface and surface integration. The objective in this paper is to apply the probabilistic risk assessment method in the optimization of CO2 injection well locations for the CO2 storage development plan. Risk comes from uncertainty, so the workflow with probabilistic risk assessment (PRA) methodology includes: 1) the risk identification and sensitivity analysis: the definition of uncertainty elements; 2) the risk analysis: the uncertainty ranges and distributions; and 3) Risk evaluation: including the individual element and composite risk evaluation. Similar to risk matrix method, two parameters used: 1) the likelihood (Pi) of occurrence of each consequence, expressed by the percentile of a threshold; and 2) the severity magnitude (Ii) of the possible adverse consequences, expressed by the coefficient of variation. The total risk is the sum of the products of Pi and Ii, displayed on the risk map. The workflow and methodology were applied in a depleted gas reservoir for CO2 storage. The main elements identified for uncertainty analysis include: 1) structural model including the top of reservoir depth and internal reservoir zonation; 2) reservoir parameters based on porosity and permeability; 3) fluid contacts. Combing all possible cases for each element, a number of scenarios of reservoir models were constructed, which are the foundation of risk evaluation. Risk score, expressed by probability, was calculated by all elements, generating a composite risk probability map, where there are different risk levels at different locations. Combining with engineering constraints, the CO2 injection well locations were selected by optimization, avoiding the area with high risk.

scholarly journals A Review on the Influence of CO2/Shale Interaction on Shale Properties: Implications of CCS in Shales

Energies ◽  
2020 ◽  
Vol 13 (12) ◽  
pp. 3200
Author(s):  
Ahmed Fatah ◽  
Ziad Bennour ◽  
Hisham Ben Mahmud ◽  
Raoof Gholami ◽  
Md. Mofazzal Hossain
Keyword(s):  
Mechanical Properties ◽  
Adsorption Capacity ◽  
Shale Gas ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Shale Formations ◽  
Shale Formation ◽  
Co2 Treatment

Carbon capture and storage (CCS) is a developed technology to minimize CO2 emissions and reduce global climate change. Currently, shale gas formations are considered as a suitable target for CO2 sequestration projects predominantly due to their wide availability. Compared to conventional geological formations including saline aquifers and coal seams, depleted shale formations provide larger storage potential due to the high adsorption capacity of CO2 compared to methane in the shale formation. However, the injected CO2 causes possible geochemical interactions with the shale formation during storage applications and CO2 enhanced shale gas recovery (ESGR) processes. The CO2/shale interaction is a key factor for the efficiency of CO2 storage in shale formations, as it can significantly alter the shale properties. The formation of carbonic acid from CO2 dissolution is the main cause for the alterations in the physical, chemical and mechanical properties of the shale, which in return affects the storage capacity, pore properties, and fluid transport. Therefore, in this paper, the effect of CO2 exposure on shale properties is comprehensively reviewed, to gain an in-depth understanding of the impact of CO2/shale interaction on shale properties. This paper reviews the current knowledge of the CO2/shale interactions and describes the results achieved to date. The pore structure is one of the most affected properties by CO2/shale interactions; several scholars indicated that the differences in mineral composition for shales would result in wide variations in pore structure system. A noticeable reduction in specific surface area of shales was observed after CO2 treatment, which in the long-term could decrease CO2 adsorption capacity, affecting the CO2 storage efficiency. Other factors including shale sedimentary, pressure and temperature can also alter the pore system and decrease the shale “caprock” seal efficiency. Similarly, the alteration in shales’ surface chemistry and functional species after CO2 treatment may increase the adsorption capacity of CO2, impacting the overall storage potential in shales. Furthermore, the injection of CO2 into shales may also influence the wetting behavior. Surface wettability is mainly affected by the presented minerals in shale, and less affected by brine salinity, temperature, organic content, and thermal maturity. Mainly, shales have strong water-wetting behavior in the presence of hydrocarbons, however, the alteration in shale’s wettability towards CO2-wet will significantly minimize CO2 storage capacities, and affect the sealing efficiency of caprock. The CO2/shale interactions were also found to cause noticeable degradation in shales’ mechanical properties. CO2 injection can weaken shale, decrease its brittleness and increases its plasticity and toughness. Various reductions in tri-axial compressive strength, tensile strength, and the elastic modulus of shales were observed after CO2 injection, due to the dissolution effect and adsorption strain within the pores. Based on this review, we conclude that CO2/shale interaction is a significant factor for the efficiency of CCS. However, due to the heterogeneity of shales, further studies are needed to include various shale formations and identify how different shales’ mineralogy could affect the CO2 storage capacity in the long-term.

scholarly journals Influence of Injection Well Location on CO2 Geological Storage Efficiency

Energies ◽  
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.

Integrated CO2 Modeling Studies to Assess CO2 Sequestration Prospect in a Depleted Carbonate Gas Reservoir, Malaysia

2021 ◽  
Author(s):  
Mohd Azran A. Jalil ◽  
Sharidah M. Amin ◽  
Siti Syareena M. Ali
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
Injection Pressure ◽  
Injection Rate ◽  
Co2 Injection ◽  
Coupled Modelling ◽  
Compositional Model ◽  
Development Concept ◽  
Modelling Study

Abstract This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution. Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field. Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process. This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance for a safe and long-term CO2 sequestration.

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