Geochemical interactions of supercritical CO2-brine-rock under varying injection strategies: implications for mechanical integrity in aquifers

Sweep efficiency during waterflooding and CO2 miscible injection can be challenging because of channeling and bypassing of injecting fluids. Some of these factors include reservoir heterogeneity, permeability contrast and gravity override. These factors contribute to reduced volumetric sweep efficiency in both sandstone and carbonate reservoirs. To study the effect of reservoir heterogeneity on pressure profile and oil recovery, and accurately describe the displacement mechanisms during seawater and CO2 flooding, an effective experimental methodology including the laboratory set-up and procedures are proposed in this paper. Dual core flooding experiments were conducted at reservoir conditions using live oil, seawater, supercritical CO2 (sc-CO2), and two composite plugs with different permeabilities. Two composite core plugs, a high permeable core plug (HPCP) and a low permeable core plug (LPCP), were placed in parallel in a coreflood apparatus. No crossflow of fluids occurred between the high and low permeable plugs. Different injection schemes were completed, which included seawater flooding, initial sc- CO2 injection, gel slug injection for conformance control and a second sc-CO2 injection. In addition, two experiments with seawater and continuous CO2 injection were completed with the same conditions in a single coreflood for comparison with the dual core flooding experiments. The results indicate that the dual core flooding technique is an effective method to evaluate the performance of IOR and EOR processes, especially involving CO2 or gas injection. The profiles of differential pressure across both HPCP and LPCP show a demonstrable distinction. The differential pressure across LPCP is higher than that of HPCP for both seawater and supercritical CO2 (sc-CO2) injection before breakthrough, and drops to levels similar to that in HPCP after breakthrough. A substantial increase of differential pressure in HPCP (up to 200 psi) was observed during base gel slug injection, which indicates that in- situ CO2-emulsion was generated and was able to block the high permeable zone and resulted in displacing fluids into LPCP, therebyimproving sweep efficiency in the LPCP. The comparisons of oil recovery by seawater and sc-CO2 injection and the pressure profile between both dual core flooding and the single core continuous sc-CO2 process (horizontal and vertical injection) are discussed in this paper.

Carbon capture and storage (CCS) has been recognized as a pivotal technology for mitigating climate change by reducing CO2 emissions. Storing CO2 in deep saline aquifers requires preserving the water-wet nature of the formation throughout the storage period, which is crucial for maintaining rock integrity and storage efficiency. However, the wettability of formations can change upon exposure to supercritical CO2 (scCO2), potentially compromising storage efficiency. Despite extensive studies on various factors influencing wettability alteration, a significant research gap remains in understanding the effects of different CO2 injection strategies on wettability in deep saline formations (DSFs). This study addresses this gap by investigating how three distinct CO2 injection strategies—continuous scCO2 injection (CCI), water alternating with scCO2 injection (WAG), and simultaneous water and scCO2 injection (SAI)—affect the wettability of gray Berea sandstone and Indiana limestone, both selected for their homogeneous properties relevant to CCS. Using a standardized sessile drop contact angle method before and after CO2 injection, along with core flooding to model the injection process at an injection pressure of 1500 psi and temperature of 100 °F with a confining pressure of 2500 psi, the results indicate a shift in wettability towards more CO2-wet conditions for both rock types under all strategies with changes in CA of 61.6–83.4° and 77.6–87.9° and 81.5–124.2° and 94.6–128.0° for sandstone and limestone, respectively. However, the degree of change varies depending on the injection strategy: sandstone exhibits a pronounced response to the CCI strategy, with up to a 77% increase in contact angle (CA), particularly after extended exposure. At the same time, WAG shows the least change, suggesting that water introduction slows surface modification. For limestone, the changes in CA ranged from 9% to 49% across strategies, with WAG and SAI being more effective in altering its wettability. This study underscores the importance of selecting suitable CO2 injection strategies based on rock type and wettability characteristics to maximize carbon storage efficiency. The findings offer valuable insights into the complex interactions of fluid–rock systems and a guide for enhancing the design and implementation of CCS technologies in various geological settings.

Produced water integration in CO2 storage using different injection strategies: The effect of salinity on rock petrophysical, mineralogy, wettability and geomechanical properties

The mechanical behavior of rock is one of the most important parameters to evaluate the potential for geological carbon dioxide (CO2) sequestration (GCS); therefore, the study of rock strength evolution and fracture behavior after CO2 injection is helpful in the long-term stability and safety of GCS engineering. In this study, uniaxial compression, Brazilian splitting and fracture tests were carried out on sandstone specimens with brine saturation or brine-super critical CO2 (scCO2) co-saturation. The influences of brine salinity and scCO2 injection on the uniaxial compressive strength (UCS), Brazilian tensile strength (BTS) and fracture toughness of sandstone were investigated. The experimental results showed that the UCS, BTS and fracture toughness of brine-saturated sandstone increased with increasing NaCl concentration but decreased after scCO2 injection. Furthermore, increments in the elastic modulus and average stiffness of brine-scCO2 co-saturated sandstone were observed relative to those under brine saturation. To investigate the change of mineral composition and micro structure during brine immersion and scCO2 injection, X-ray diffraction analysis, scanning electron microscopic observation and mercury intrusion porosimetry test were performed. Composition changes and dissolution of quartz were not observed, but many micro pores were created after scCO2 injection, thus increasing the porosity and reducing strength and fracture toughness. Finally, the mechanism of brine-scCO2 saturation in altering mechanical properties was discussed. These experimental results are expected to increase the understanding of the mechanical response of rock after scCO2 injection in deep saline aquifers.

Study of reservoir rock and caprock integrity in geo-sequestration of carbon dioxide

Biomineralization, through microbially, thermally, or enzyme induced carbonate precipitation (MICP/TICP/EICP), is a cost-effective cementation process for changing porosity and permeability in the subsurface. This study aims to optimize compositional and injection parameters for biomineralization fluids, and to develop understanding of the interactions between geochemical reactions and fluid transport properties at the pore (micron) scale. Utilizing real-time in situ X-ray computed tomography (XCT), we compare traditional Microbially Induced Calcium Carbonate Precipitation (MICP) with novel thermally delayed (TICP) and Enzyme Induced Calcium Carbonate Precipitation (EICP) in a range of lithologies. This allows us to investigate the impact of mineralogy, grain size distribution, and temperature as well as the injection composition and strategy. We present quantitative analysis of crystal locations, the volume of carbonate and of individual crystals, and the effect of crystals on permeability and flow localisation over time. Coupled to measured changes in microstructural and macroscopic properties over repeated precipitation and dissolution cycles we present refined models of reactive transport for different injection strategies, and identify the optimal treatment strategy for different subsurface applications. This includes validation of the durability of precipitated calcite seals during dissolution phase, simulating the behaviour of CO2-enriched brines.This work provides the underpinning understanding principles of crystal formation, growth and hydrodynamic feedback mechanisms necessary for accurate modelling of reservoir scale dynamic processes.  However, we also show how TICP and EICP strategies can improve performance of real-world Carbon Capture and Storage systems, driving more homogeneous, widely distributed and larger volumes of precipitated CaCO3 by maintaining permeability during treatment at higher degrees of cementation when compared to MICP. We also show how variable injection strategies allow improvement of other physical properties (e.g. mechanical strength) and enables the addition of highly conductive additives or phase change materials without reducing precipitation and flow. Using CaCO3 precipitation we observed a 470% increase in the thermal conductivity of unsaturated quartz sand after 9 cycles of MICP, and an 800% increase following addition of 5 wt% expanded natural graphite (ENG). Our findings also demonstrate the compatibility of integrating paraffin as a phase-change material within the porous matrix of ENG prior to MICP/EICP treatment significantly increasing specific heat capacity. These new geomaterials have widespread implications for thermal energy storage, specialized geothermal grouts/backfill, shallower wells and reduced geothermal energy costs.The project's outcomes impact the commercialization of engineered biomineralization and its role in the subsurface energy transition.

Laboratory testing plays a critical role in assessing the suitability of storage sites for Carbon Capture and Storage (CCS) projects. In geomechanical analysis, rock mechanics testing is essential for evaluating the elastic and strength properties of overburden and reservoir rocks, which are critical for calibrating 1D geomechanical models to predict caprock and reservoir mechanical integrity and stress regime. Given the potential degradation of rock elastic and strength properties due to CO2 exposure, CO2-rock interaction experiments are necessary to assess rock integrity and to understand long-term mechanical property changes. This study explores the impact of CO2 interaction on the mechanical properties of clastic reservoir rocks, focusing on key geomechanical parameters such as Young’s modulus, Poisson’s ratio, unconfined compressive strength (UCS), cohesion, friction angle, and tensile strength. Rock samples from J-field, offshore Peninsular Malaysia were subjected to CO2 saturated brine injection, followed by a 14-day static reaction period under in-situ conditions. Pre- and post-treatment analysis revealed significant reductions in UCS (23.9%), cohesion (20.5%), friction angle (8.8%), and Young’s modulus (21.5%), along with a 7.5% decrease in Poisson’s ratio and a tensile strength reduction of 26%. Furthermore, Uniaxial Pore Volume Compressibility (UPVC) tests indicated minor matrix deformation without pore collapse, suggesting that the rock matrix retains mechanical integrity in the transient pressure variations. This study underscores the importance of comprehensive laboratory analysis in qualifying CO2 storage reservoirs for CCS projects. The absence of certain field data, such as Global Positioning System (GPS) measurements, can be addressed through alternative indicators like UPVC tests which provide insights into reservoir integrity and compaction behavior. Additionally, findings from post-CO2 degradation analysis are vital for integrating rock property changes into 3D/4D coupled geomechanics-dynamic models, ensuring accurate long-term predictions of CO2 behavior in the subsurface.

What have We Learned about CO2 Leakage from Field Injection Tests?

What have we learnt about CO2 leakage from CO2 release field experiments, and what are the gaps for the future?

CO2-induced mechanical behaviour of Hawkesbury sandstone in the Gosford basin: An experimental study

Carbon Capture and Storage (CCS) is a critical technology for mitigating CO₂ emissions and combating climate change. However, ensuring the long-term stability and integrity of subsurface formations used for CO₂ storage remains a major global challenge, as the formations of interest may be exposed to CO₂ for hundreds or even thousands of years. This study addresses this challenge by evaluating the impact of CO₂ storage time on the petrophysical, chemical, and geomechanical properties of Berea sandstone, a commonly used analog for saline aquifers. The objective of the research is to assess early-stage alterations in sandstone properties during CO₂ exposure, providing insights for predictive modeling and long-term CCS performance assessments. By understanding these early transformations, we aim to offer a clearer picture of the implications for long-term storage, enhancing CCS monitoring and strategy optimization. In this experimental investigation, Berea sandstone samples were exposed to CO₂-saturated brine under reservoir conditions (1500 psi and 150°F) for 30 and 90 days. These controlled laboratory experiments, while short relative to geological timescales, are designed to simulate key early-stage interactions between CO2, rock, and fluid. A comprehensive suite of characterization techniques was employed to capture changes in the rock's physicochemical and mechanical properties. These techniques included Routine Core Analysis (RCA) to measure porosity and permeability, Nuclear Magnetic Resonance (NMR) for pore structure analysis, Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) to assess fluid chemistry changes, X-ray Diffraction (XRD) for mineralogical changes and ultrasonic acoustic velocity testing to evaluate elastic properties. This approach allows us to analyze both the near-term effects of CO₂ exposure and the potential for scaling up observations to long-term predictions. The study revealed limited early-stage alterations in the physicochemical and and mechanical properties of Berea sandstone during CO₂ exposure. Minor changes were observed in mineral composition, fluid chemistry, and pore structure after 30 and 90 days of storage under representative-reservoir- conditions. These changes, including trace mineral dissolution, modest shifts in pore size distribution, and slight reductions in permeability, and stable dynamic moduli across all samples—remained within the range of experimental variability and did not indicate significant degradation. While the extent of transformation was minimal, the findings provide important early evidence of CO₂–rock–brine interactions that may evolve over extended timeframes. This highlights the value of controlled short-term laboratory experiments in informing long-term CCS behavior, particularly when coupled with reactive transport modeling. Ultimately, the results contribute to improved predictive frameworks, better risk assessment, and more effective design of monitoring and storage strategies for secure geological CO₂ sequestration.

Carbon capture and storage (CCS) stands as a key technology for mitigating CO2 emissions, with depleted oil and gas fields being excellent candidates for geological storage. However, injection of relatively cold, high-pressure CO2 into higher temperature, low-pressure hydrocarbon reservoirs can induce cooling and potential freezing due to the temperature difference between the injected fluid and the reservoir, as well as Joule-Thomson cooling caused by the rapid expansion of the fluid upon entering the reservoir. This may impact wellbore integrity, and near-wellbore stability and injectivity, posing challenges for safe and cost-effective storage. To be able to accurately predict the impact of cooling on storage operations, it is important to quantify the impact of temperature cycling on the mechanical and transport properties of the rock formations in the near-wellbore area.To address this, we performed thermal cycling experiments under realistic in-situ pressure-temperature conditions on sandstone analogous to typical hydrocarbon reservoir material. We used a novel apparatus comprising a hydrostatic pressure vessel placed inside a climate chamber providing a temperature range of -70°C to +180°C. Bleurswiller sandstone (Vosges, France; 24% porosity) was subjected to temperature changes from 100 °C to +40, +5, or -20°C at constant pore fluid pressure (5 MPa; 0.85 M NaCl brine) and confining pressure (10 or 25 MPa, i.e. similar to reservoirs of up to ~3 km depth). The effect of the rate of temperature change, brine saturation and the number of cycles on the volumetric behaviour of the sandstone were systematically investigated. Thermally treated samples were subsequently subjected to permeability measurements and conventional triaxial compression to evaluate the impact of confined temperature cycling on the transport and mechanical properties.In all our thermal cycling experiments, we observed permanent volume change (compaction) with each cycle, though the amount of compaction decreased with subsequent cycles. Furthermore, our results showed that confined temperature cycling did not significantly alter the mechanical properties (strength, elastic properties) of Bleurswiller sandstone. This is in contrast to the strength reduction observed in other porous sandstones after unconfined thermal cycling. However, our thermally treated samples did exhibit a significant reduction in permeability by several orders of magnitude (κ = 10-15 to 10-16 m2 post-treatment) compared to untreated reference samples (initial κ = ~10-14 m2). Overall, permeability roughly decreased with increasing brine content (i.e. from dry to fully brine saturated), increasing number of thermal cycles, and increased temperature amplitude (i.e. more cooling). Temperature change rate did not affect the permanent volumetric strain or permeability reduction in samples that were only cooled. In experiments achieving sub-zero temperatures, including pore fluid freezing, slower temperature changes resulted in less permeability reduction.

In the latest offshore developments to be carried out in Brazil, supercritical CO2 (scCO2) injection into the fields is being considered as a potential application. This injection operation will gradually lead to high levels of CO2 in the produced fluids, creating additional challenges for the materials used in riser systems specifically designed for such applications. Upcoming developments are being carried out in ultra-deep waters which can reach 2500 m. Flexible pipes are considered one of the options for both production and CO2 injection pipes due to performance in such scenarios and fast implementation when compared with conventional rigid riser systems. However, the high levels of CO2 and the presence of water in the conveyed fluids has raised some questions about the utilization of polyamides in such applications, and the applicability of API 17 TR2 to properly predict the hydrolysis of polyamides in such extreme environments. Based on this new scenario, GE Oil & Gas has implemented a specific R&D program to evaluate the hydrolysis behavior of polyamides within environments containing high CO2 partial pressure, exceeding 400 bar. This paper summarizes the experimental results assessed during the test program carried out and discusses the applicability of polyamides in both oil/gas production and CO2 injection flexible pipes. Introduction Though CO2 reinjection into geological formations is not a new subject, in recent years its importance has gradually increased within the offshore industry, due mainly to adoption of carbon capture and storage (CCS) and enhanced oil recovery (EOR). The feasibility of offshore reinjection operations was demonstrated in 1996 with the development of the Sleipner field in Norway as part of a CCS project [1], and again in 2004 in Algeria with the development of the In Salah natural gas field [2] with approximately one million tons of CO2 per year being separated from the produced natural gas and then reinjected into the geological formation. In order to make CCS cost effective and economically feasible, the CO2 reinjection may be used as part of an EOR process to improve production and fight reservoir depletion [3]. The need for CCS is even greater in the development of offshore projects in the Brazilian pre-salt cluster in ultra-deep water, an environment with several technological challenges. According to Nakano [4] the produced oil in this new exploratory province will present a high gas : oil ratio (GOR) and the dissolved gas will present a CO2 concentration ranging from 8 to 12% during the first years of production. Based on this scenario, CCS and EOR programs will be put in place [4] [5] to comply with environmental regulations and make the project more cost effective.

Carbon dioxide (CO2) is a kind of greenhouse gas affects atmospheric temperature. The deep coal seam is a potentially favorable geological body for CO2 storage, as it can be coupled with enhanced coalbed methane production, which can offset partly the cost of storage. CO2 injection to the deep coal seam would be in supercritical state, i.e., ScCO2, which affects the mechanical properties of coal seam more significantly. In this paper, a study was initiated to investigate the effect of ScCO2 adsorption and pore pressure on the mechanical properties of anthracite by the mechanical testing system, and observations were conducted to analyze the micro-damage of anthracite before and after ScCO2 injection by the scanning electron microscope. The results indicated that the strength of anthracite would be reduced with the pore pressure increases. Corresponding to the He injection pressure with 4 MPa and 8 MPa, under the condition of confining pressure 10 MPa and temperature 40 °C, the compressive strength reductions were 10.2% and 35.9%, the elastic modulus reductions were 10.9% and 24.7%, and Poisson’s ratio increases were 16% and 49%, respectively. The strength of anthracite would also be reduced by ScCO2 adsorption. Corresponding to the ScCO2 injection time for 3 h and 6 h, the compressive strength reductions were up to 42.6% and 61.1%, the elastic modulus reductions were up to 10.4% and 41.3%, and Poisson’s ratio increases were up to 8.92% and 35.71%, respectively. The mechanical weak planes were produced by ScCO2 injection, which could reduce the mechanical strength of anthracite. Compared to anthracite samples with the He injection, the elastic modulus of anthracite with ScCO2 injection was reduced by 21.9%, the compressive strength was reduced by 23.9%, and the Poisson's ratio was increased by 5.3%. The results also indicated that the mechanical strength reduction of anthracite was more significantly caused by ScCO2 injection for the superimposed effect of adsorption and pore pressure.

In order to decrease Carbon Dioxide (CO2) emissions, Oxy-Fuel Combustion (OFC) technology with Carbon Capture and Storage (CCS) is being developed in Internal Combustion Engine (ICE). In this article, a numerical study about the effects of intake charge on OFC was conducted in a dual-injection. Spark Ignition (SI) engine, with Gasoline Direct Injection (GDI), Port Fuel Injection (PFI) and P-G (50% PFI and 50% GDI) three injection strategies. The results show that under OFC with fixed Oxygen Mass Fraction (OMF) and intake temperature, the maximum Brake Mean Effective Pressure (BMEP) is each 5.671, 5.649 and 5.646 bar for GDI, P-G and PFI strategy, which leads to a considerable decrease compared to Conventional Air Combustion (CAC). [Formula: see text], [Formula: see text] and [Formula: see text] of PFI are the lowest among three injection strategies. With intake temperature increases from 298 to 378 K, the reduction of BMEP can be up to 12.68%, 12.92% and 12.75% for GDI, P-G and PFI, respectively. Meantime, there is an increase of about 3% in Brake Specific Fuel Consumption (BSFC) and Brake Specific Oxygen Consumption (BSOC). Increasing OMF can improve the performance of BMEP and BSFC, and the trend is more apparent under GDI strategy. Besides, an increasing tendency can be observed for cylinder pressure and in-cylinder temperature under all injection strategies with the increase of OMF.