Abstract In many respects formation damage challenges in CO2 storage wells are similar to those in conventional oil and gas production wells and water and gas injection wells. But there are some differences from "conventional" well formation damage challenges. This paper outlines some issues specific to CO2 injection wells and proposes changes in focus prior to and during drilling and completion of these wells. CCS (Carbon Capture and Storage) store can generally be split in to two categories – saline aquifers and depleted hydrocarbon reservoirs. Wells drilled and/or completed in these stores share some well injectivity challenges with conventional wells but also have some challenges specific to the store properties. In conventional injection wells it is generally accepted that well clean-up or back production prior to injection is beneficial as formation damage necessarily induced during well drilling and clean-up may be partially or fully removed. For saline aquifers and depleted hydrocarbon stores, well clean-up is normally not possible or practical. Direct injection after well completion is often required. A new workflow capturing the key steps required to assure optimum well injectivity over the well life cycle has been developed and will be outlined in the paper. This includes but is not limited to: detailed analysis of CO2 phase behaviour in and beyond the lower completion; lower completion selection criteria specific to CO2 stores; laboratory testing and modelling focussed on CO2 store formation damage challenges; direct injection challenges and successful mitigations; ice scale and hydrate challenges in CO2 storage wells. With increasing focus on CO2 storage globally, the workflow outlined presents an integrated approach to formation damage challenges. It demonstrates that although many of the challenges are similar to those in conventional wells, there are also some that are different and unique – the same, but different!
90Review of failures for wells used for CO2 and acid gas injection in Alberta, Canada
Review of failures for wells used for CO2 and acid gas injection in Alberta, Canada
12Wellbore Dynamics of Acid Gas Injection Well Operation
This paper presents insights gained from analyzing and modeling acid gas (H2S and CO2) injection well performance over the last 13 years. As the world increasingly develops oil and gas reservoirs that contain significant concentrations of H2S and CO2, the number and size of acid gas injection facilities and their associated acid gas injection wells will increase. A methodology to estimate wellhead operating pressures satisfies a key requirement for design of the injection wells and sizing of the acid gas injection compressors. It may also help inform engineering and operations personnel, and regulatory agencies, of the complex behaviour of acid gas injection wells. The initial impetus for this work was an operator who increased the acid gas injection rate on a well yet saw virtually no change in wellhead operating pressure, which is inconsistent with water injection well operations. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behaviour with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore. Pressure gradients in aquifers or reservoirs suitable for acid gas sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 103m3/d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, fluid composition and wellhead temperature on wellhead pressure. Depending on conditions, injected acid gas may undergo phase transitions from a gaseous or two-phase mixture at the wellhead to liquid at the sandface and back to gaseous or supercritical out in the reservoir. The complex interactions between temperature, phase behavior, fluid density and pressure can lead to unusual operating characteristics including an increased injection rate or sandface pressure with little or no change in wellhead pressure.
Read more2Importance of Surface-Subsurface Integration in CCS System Design
The main objective of this study is to investigate the impact of subsurface conditions on surface networks and vice-versa to highlight correlated challenges and establish best-practice guidelines to be taken into consideration for carbon dioxide (CO2) injection networks to optimize surface and subsurface operations. This study involved CO2 transport and injection well modelling for a variety of surface and subsurface conditions. This includes the simulation of onshore and offshore transport conditions as well as injection into depleted reservoirs and saline aquifers. Steady state and transient operations were performed on the injection well to investigate the surface and subsurface challenges associated with CO2 phase behavior in the system. In this work, an integrated CO2 transport and injection network was modelled for various operating scenarios during the life cycle of a CCS project. The challenges encountered in the entire system including Joule-Thomson (JT) cooling, hydrate formation and multiphase flow are highlighted with field case studies presented. In the context of Carbon Capture, and Storage (CCS) projects, it is essential for CO2 injection wells to meet projected CO2 injection rates for both economic as well as regulatory requirements. The regulatory consequences could be significant, with the operator potentially held responsible for carbon credits until adequate well capacity is attained. There are several subsurface and surface conditions which impact the performance of either the surface and subsurface operations and these operational scenarios are discussed in an integrated study so that the entire CCS system can be optimized to meet transport and injection requirements.
Read more18Well integrity assessment for CO2 injection
PurposeIn the carbon dioxide capture and storage (CCS) project, the integrity of CO2 injection wells plays a vital role in the long‐term safety of CO2 storage. The authors aim to practically investigate possible CO2 leakage of a CO2 injection well section during the injection operation and shut‐in by the thermomechanical FEM simulation. The application of numerical simulation to the CO2 injection well deep underground is the first step that will help in the quantitative evaluation of the mechanical risks.Design/methodology/approachThe injection of CO2 at a temperature different from those of the well and the surrounding geological formation is likely to cause different thermal deformations of constitutive well materials. This could lead to cement cracking and microannuli openings at the interfaces of different materials such as casing/cement and cement/rock. In this paper, the possibility and order of magnitude of cement cracking and microannuli creation in the cross section of the well are assessed from a numerical case study within a classical thermomechanical finite element model framework.FindingsThe possibility of compressive failure and tensile cracking in the cement of the studied wells due to CO2 injection is small unless a large casing eccentricity or an initial defect in the cement is present. Some microannuli openings are generated at interfaces cement/casing and/or cement/rock during the CO2 injection because of different thermal shrinkage of each material. However, the width is not important enough to cause significant CO2 leakage under the studied conditions. The use of “flexible” cement especially developed for oil well applications could mitigate the risk of cement cracking during CO2 injection.Originality/valueNumerous experimental studies on the chemical deterioration of the cement under severe conditions have been carried out. On the other hand, only a few investigations have focused on the mechanical behavior under thermal/pressure changes related to CO2 injection. In this paper, the quantitative analysis to investigate cement cracking and microannuli formation is achieved to help in the identification of possible mechanical defects to cause CO2 leakage. In addition, the discussion about the risk of the possible casing eccentricity and the application of flexible cement in the oil and gas field to CO2 injection well could be practically useful.
Read more15Lesson learned from the assessment of planned converted CO2 injection well integrity in Indonesia – CCUS project
Lesson learned from the assessment of planned converted CO2 injection well integrity in Indonesia – CCUS project
13Improved Production Strategy for Enhancing the Immiscibile and Miscible CO2-Assisted Gravity Drainage Oil Recovery
Fundamental understanding and application of process parameters in numerical simulation that leads to optimized gravity drainage oil recovery at field scale is still a major challenge. Reservoir simulations studying the effects of well patterns and type of gas injection wells have not been reported so far. In first ever attempt, the mechanistic benefits of production strategy on gravity drainage oil recovery are identified in this paper. Effects of irregular and regular well patterns and vertical and horizontal gas injection wells are investigated using a fully compositional 3D reservoir model in both the secondary immiscible and miscible modes under the conditions of voidage balance, constant injection and production pressure and injection rates below the critical rate. Regular well pattern provided longer oil production time at a constant rate until CO2 breakthrough compared to irregular well pattern. It then dropped almost vertically at the same cumulative oil recovery even at higher production rates. However, gravity drainage oil recovery was higher at higher rate combination after CO2 breakthrough. Results also suggested that the regular pattern could result in horizontal CO2 floodfront parallel to the horizontal producers, maintaining reservoir pressure, thus optimizing the oil recovery by additional 2.5% OOIP. Vertical injection and horizontal production wells in both the immiscible and miscible modes provided nearly identical cumulative gravity drainage oil recovery compared to the combination of horizontal injection and production wells in the regular well pattern. This suggests that the type of injection wells may not be a significant factor to impact the CO2-assisted gravity drainage mechanism. Results obtained herein would help in the optimization of CO2-assisted gravity drainage EOR process.
Read more7Numerical simulation of the coupled thermal-hydro-mechanical fields for evaluating CO2 geo-sequestration storage in deep saline aquifers of Hainan Fushan Sag, China
Geo-sequestration storage of CO2 in saline aquifers is an important technological option to reduce carbon emissions in China in the future. The theory of geo-sequestration storage of CO2 in saline aquifers involves complex physical operations and chemical phenomena among reservoir stress, seepage, and temperature fields, and the numerical simulation models coupling thermal-hydro-mechanical (THM) fields are widely applied to analyze the evolution of multiphysical processes in CO2 reservoirs. Based on the geo-sequestration storage project of saline aquifer CO2 in Fushan Sag, Hainan Province, under the premise of considering the change of permeability and porosity after the mineralization of CO2 in the rock reservoirs, this study simulates the evolution of temperature, stress, and seepage fields during the sequestration process of saline aquifer Continuous CO2 injection wells clarifies the range of influence of the temperature field, seepage field, and the boundary of its stress field of saline aquifer Continuous CO2 injection wells in different sequestration periods. It reveals the influence mechanism of the fault structure on the reservoir CO2 sequestration pressure and capacity, and evaluates and estimates the CO2 injection storage capacity of Fu 1# well in Fushan Sag and on this basis. The THM numerical simulation model proposed in this study plays a crucial role in guiding theoretical evaluations of the CO2 geo-sequestration potential in saline aquifers and determining its technical parameters, thereby offering significant value for engineering applications.
Read more21Cement-Sheath Wellbore Integrity for CO2 Injection and Storage Wells
It is critical that CO2 injection and storage wells have wellbore integrity to help prevent leakage of CO2 during the injection period, as well as long-term zonal isolation to sustain the loading conditions of pressure testing, completions, injection, shut-in, and stimulation treatment. This paper highlights the salient engineering design features of planning a successful cementing-job operation for extended-reach drilled (ERD), carbon capture and storage (CCS) wells. Corrosion in Portland cement caused by carbonic acid is a well-documented phenomenon. CO2 injected into geologic formations for underground storage purposes can be converted into various concentrations of carbonic acid with different levels of pH in the formation water surrounding the well, depending on conditions such as temperature, pressure, and the formation rock chemical components. The use of non-Portland cement is often recommended in harsh environments (pH<4) to help avoid any negative impact on long-term well integrity. In addition, the cement should have long-term mechanical resiliency against the anticipated future loading conditions of pressure testing, completions, injection, shut-in, and stimulation treatment. A detailed transient wellbore-temperature analysis was carried out for estimating the wellbore and tubular fluid-temperature profiles during the planned well operations. Based on the estimated temperature profiles, wellbore-pressure conditions, and fluid properties, a rigorous cement-sheath mechanical-integrity analysis was performed following a finite-element analysis (FEA) approach. It was found that the use of non-Portland cement alone might not be sufficient for long-term wellbore integrity. Customized non-Portland cement systems were developed with modified mechanical properties to help ensure appropriate mechanically resilient properties for the long life of a CCS well. Comparative FEA with non-Portland cement and mechanically modified non-Portland cement at the top of tail cement and casing shoe for ERD CCS wells is detailed.
Read more2Analysis of CO2 injection strategy and storage in the kujung formation using reservoir simulation
Analysis of CO2 injection strategy and storage in the kujung formation using reservoir simulation
Real-Time Carbon Dioxide Injection Monitoring Through Fiber Optics: Physics-Based Modeling of Distributed Temperature Sensing Data for Time-Lapse Assessment of Fluid Properties
<ns0:p>This paper presents an innovative modeling of continuous fiber-optic measurements to improve the dynamic characterization of injection wells during the early stages of carbon capture and storage (CCS) projects. The approach uses distributed temperature sensing (DTS) data collected along the well profile to map the thermal behavior in real time during three key phases: before injection begins, during the initial regime when carbon dioxide (CO2) displaces the brine in the tubing and fills the borehole, and during full stable operation. This physics-based methodology provides fluid mapping based on DTS, as well as a comprehensive description of the well thermal performance, essential for understanding and optimizing CO2 injection. The results obtained during CO2 injection into a depleted natural gas reservoir demonstrate the present method. The injection well completion is equipped with permanent fiber-optic cables for continuous DTS monitoring down to the production packer. While standard DTS can be used to monitor the well thermal performance during steady-state operations, other factors are essential for accurately monitoring the distributed temperature profile during transient operations. This study begins with an analysis of brine displacement from the tubing into the borehole during well commissioning. The dynamic behavior of CO2 during these operations led to thermal effects along the well tubing, which were addressed through an innovative analysis of DTS data. A reprocessing of the space-time temperature measurements was implemented to distinguish between the downward movement of gas and liquid within the tubing. This made it possible to locate the real-time position of the contact between CO2 and brine in the tubing, thanks to their different physical properties. DTS measurements and reprocessing outputs were successfully used to calibrate a physics-based well simulation model that describes fluid dynamics and thermodynamics, involving complex well geometries and multiphase flow conditions. Thus, the DTS-calibrated physics-based simulation model provided insight into the well’s thermal evolution and allowed for the real-time computation of important physical properties, such as the density, phase, and pressure profiles of CO2. The presented methodology provides strong dynamic characterization of CO2 injection wells from the beginning of a CO2 transportation and storage (T&S) project. The resulting calibrated wellbore models are essential for CO2 injection optimization, flow assurance, and risk management. While there are several approaches to maximize information from permanent DTS data, quantitatively using temperature evolution for dynamic modeling is a novel technology that can shed light on the early and uncertain stages of CO2 T&S projects.</ns0:p>
Read more5Wellbore Integrity Impact on Carbon Leakage to Ensure Safe Geological Sequestration
Secure and safe geological sequestration is critical for the successful deployment of carbon capture and storage (CCS) projects and to mitigate global warming. Oil/gas reservoirs and saline aquifers, that are suitable for CO2 sequestration, often have older pre-existing wells near the potential CO2 injection wells. The legacy producing and abandoned wells have the potential to behave as CO2 leakage pathways, despite the existence of a good seal formation or structural certainty. In this study, this poorly understood and largely unknown leakage potential is researched to quantify the carbon leakage rate along one legacy well when carbon is injected into a storage formation in the Denver-Julesburg (DJ) Basin. This study investigates the risk of containment loss for a leaky well using a one-square-mile section of the DJ Basin. The results show that the completion of an older wellbore has a significant effect on the leakage rate results. A small portion (10-8) of the injected carbon can leak via a multi-segmented wellbore, while around 2.5% CO2 can leak to the drinking water layer via an open wellbore. Our results indicate that for secure carbon sequestration, a good geological storage site should be kept away from wells that have a surface casing depth of 476 ft or shallower and were drilled before 1994 in Colorado. The effective well permeability highly impacts the leakage rate, implying the importance of estimating the most representative value/range for this parameter. This risk assessment research is a part of the pre-feasibility study to support potential large-scale geological carbon storage operations in Colorado.
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2Perspectives of Geological CO2 Storage in South Korea to Cope with Climate Change
Rapid industrialization and urbanization in the 20th century have led to increasing volumes of carbon dioxide being released into the atmosphere[...]
Read more1Geological Storage for CO2
Geological Storage for CO2
Distributed Temperature Survey Guided Coiled Tubing Stimulation of the First CO2 Injector Well in UAE
This paper outlines the successful application of distributed temperature sensing (DTS) and fiber-optic-equipped coiled tubing (FOE-CT) in stimulating the first Carbon Dioxide (CO2) injector well in the UAE. A Real-Time Assisted Matrix Stimulation Engineering (RTA-MSE) workflow enabled accurate injection profiling over a 600-ft perforated interval, optimizing acid placement and volume. The treatment resulted in a more than five-fold increase in injectivity, with DTS confirming uniform post-treatment acid distribution. To mitigate coiled tubing (CT) exposure to the CO2 environment and avoid integrity risks, the wellbore fluid was initially displaced back to the formation using fresh water. In a single CT run, five DTS passes were recorded: DTS-1 for geothermal baseline, DTS-2 during freshwater injection to define the pre-treatment profile, and DTS-3 warm back to confirm flow distribution. Based on this data, the 28% hydrochloric acid treatment, enhanced with a nitrified stage, was optimized and pumped. DTS-4 and DTS-5—post-treatment injection and warm back—validated stimulation effectiveness. The CT was then safely retrieved, concluding the combined intervention and evaluation operation. This CO2 injector well—the first of its kind in the Middle East—was drilled into a saline aquifer. Post-drilling, it achieved an initial injectivity of 7 bpm at 1,000 psi surface injection pressure. Distributed Temperature Sensing (DTS) profiling identified three distinct injection zones across the 600-ft perforated interval. Zones 2 and 3, located in the upper section, showed limited injectivity, which correlated with petrophysical interpretation and water injection simulation. In contrast, Zone 1, the lowermost section, exhibited uniform injection. Given the vertical well architecture, a nitrified acid stage was incorporated into the treatment to enhance coverage of the upper zones. Post-stimulation DTS data confirmed a significantly improved and uniform injection profile across all zones. As a result, the well's injectivity index increased by a factor of 5. This case validates the effectiveness of fiber-optic-enabled coiled tubing with real-time DTS in optimizing acid placement and improving zonal coverage in challenging CO2 injection environments. The methodology offers a replicable stimulation workflow for similar injector wells across the region, advancing stimulation design and monitoring practices in the petroleum industry. This paper presents the first documented case in the UAE of using DTS and downhole measurements to evaluate and optimize acid stimulation in a vertical CO2 injector. By profiling injection across a 600-ft perforated interval in real-time, the study demonstrates how DTS-enabled workflows can ensure uniform stimulation and significantly enhance injectivity, offering a new benchmark for matrix acidizing in CO2 injection wells across the industry.
Read moreReduction of Carbon Emission in East Java Power Generation Sector Through The Use of Saline Aquifer as CO2 Storage - A Conceptual Study
East Java region, as one of the most industrialized regions in Indonesia, is a significant contributor to national greenhouse gas (GHG) emissions, and therefore may play a significant role in supporting the national commitment to reach net zero emissions (NZE). This study is made to provide an example of how a conceptual CCS scheme using a saline aquifer is applied in the region. Tanjung Awar-awar coal-fired power plant, which is located in the Tuban city area on the northern coast of East Java, is selected as the GHG source. With its power generation capacity of 2 x 350 MW, it emits 4.5 Mt CO2e annually. The extensively distributed Kujung carbonate formation is chosen as the CO2 saline aquifer storage. Amidst the typical data rarity commonly faced in preliminary studies on saline aquifers, modeling for CO2 storage has been performed using all available primary and secondary data from all available sources. The most likely estimate of storage resource shows 479 Mt CO2e (status: 3U in SRMS classification system), with its A2 block possessing 162.78 MtCO2 storage resource. The CO2 injection scheme is essentially a volumetric balancing between CO2 emissions and injection rates through injection wells. Well injection capacities are estimated, and must be able to cope with CO2 emissions from the power plant. Accordingly, two CCS scenarios of 50% CO2 capture (Scenario A; 4,671 tons/day) and 100% CO2 capture (Scenario B; 9,342 tons/day) are set. To serve the two scenarios, four (4) and eight (8) horizontal wells are needed, respectively. A similar approach has also been made for vertical injection wells. Following the assumptions set in the CCS scheme, a total of 34,098,300 tons and 68,189,300 tons of CO2 can be stored in a 20-year injection permit for Scenario A and Scenario B, respectively. Nonetheless, these figures constitute just fairly small fractions of the Kujung A2 block’s storage resource. This shows the huge potential of the Kujung Formation to act as a saline aquifer storage for CCS schemes in the East Java region. This also presents the potential of the Kujung Formation to sustain multi-CO2 sources and prolonged injection schemes. Despite many challenges faced, especially in relation to data scarcity, the results may serve as a reference for more detailed project-based studies in the future.
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