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Results
Geochemistry Study for the CO2-H2S Injection for Storage: Experimental and Modelling
Zaidin, M. F. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Razak, A. A. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Amin, S. M. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Mohsin, N. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Pin, Y. W. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Tewari, R. D. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia)
Abstract Realizing the risk and possible impacts of the H2S presence in the injected CO2 towards the overall of Carbon Capture and Storage (CCS) operation in carbonate reservoir, it is recommended to have an accurate knowledge of these behavior for safe and efficient CO2 injection and storage in the reservoir formation. Limited data available from the literature suggested that additional laboratory studies are required to measure and understand the behaviour of the CO2-H2S mixture on the carbonate rock reactions, and therefore the aim of the study is to measure the key geochemical reaction kinetics parameters between injected CO2- H2S, brine and reservoir rocks and their effects to the fluid, rock properties (chemistry, mineralogy, porosity, permeability). The core samples from Y Field have been selected and used as a case study since Y Field has been identified as one of the potential CO2- H2S storage sites and there are preserved core samples available. Briefly, the mixture of CO2-H2S gas with the H2S concentration level up to 500 ppm is co-mixed with brine water and aged with core samples under Y Field reservoir condition for duration of 30 days via static batch ageing using PT chamber. Cores and effluent collected at the end of ageing days were analyzed to measure the changes on the key geochemical parameters (i.e, rock porosity, permeability, mineralogy & images from CT scan) between post-ageing and pre-ageing. The experimental results will validate the geochemical models at such H2S concentrations, and it will greatly enhance the accuracy of the models used to predict CO2-H2S storage capacity and containment for high H2S fields. This study provides critical information on the kinetic rates, which are crucial inputs for both short- and long-term projections. The incorporation of these accurate data into the models will improve their ability to predict the behaviour of CO2 and H2S in the storage and containment process, thereby providing more reliable and actionable insights for future high H2S fields.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.67)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
Flow-Geomechanics-Geochemistry Simulation of CO2 Injection into Fractured Sandstones and Carbonates
Mura, Miki (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, US.) | Sharma, Mukul M. (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, US.)
Abstract CO2 storage in reservoirs with natural and/or induced fractures is an efficient method to sequester CO2 because of their high and sustained injectivity. Past work has focused on storage of CO2 in the pore space and in the dissolved state within the brine. This research shows that geochemical reactions involving the CO2 interacting with reservoir minerals (in different lithologies) can also play a very important role in sequestering the CO2. A fully integrated 3-D reservoir simulator that includes single-phase flow, geomechanics, and geochemistry is introduced. The geochemical capability in the simulator predicts flow and geomechanical behavior due to geochemical reactions triggered by CO2 injection. The simulation models a reservoir with an induced planar fracture. The amount of CO2 that is sequestered and the extent of mineral dissolution and precipitation are computed. To demonstrate the impact of rock lithology, the model is used to simulate CO2 injection into a sandstone, a limestone, and a dolomite reservoir. The paper also investigates two different CO2 rich brines to investigate the impact of the brine composition. It is shown that the portion of the CO2 injected that reacts with the minerals and is then converted into other mineral precipitates depends largely on the mineralogy of the reservoir and the composition of the injection fluid. Limestone and dolomite reservoirs are much more susceptible to mineral dissolution and precipitation resulting in more CO2 sequestration and larger changes in injectivity over time when injection fluid is compatible with the host rock. It is shown that the fracture geometry determines the location of mineral dissolution and precipitation. This alteration of the mechanical and flow properties of the reservoir rock and fractures resulting from mineral alteration can also change the mechanical properties of the rock and result in more fracture growth and enhance or impede propagation of CO2 plume or CO2 charged water. Results showing the pros and cons of injecting CO2 into fractured wells in sandstone and carbonate reservoirs are presented considering the brine types to charge CO2. Our results show, for the first time, the clear differences that arise when sequestering CO2 in limestone, dolomite and sandstone reservoirs. The impact of geochemical reactions in realistic injection well scenarios is quantified. Results are also presented to show the pros and cons of using hydraulically fractured wells for CO2 injection in both lithologies.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
Assessing the Impact of CO2-H2S at 400 ppm for Storage: A Geochemistry Perspective
Zaidin, M. F. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Razak, A. A. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Abdullah, W. M. S (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia) | Tewari, R. D. (Department of Carbon Capture Utilisation and Storage, PETRONAS Research Sdn. Bhd., Kajang, Selangor, Malaysia)
Abstract The presence of impurities, such as H2S, in CO2 injection carries a higher risk of sulfide mineral precipitation. This can have detrimental effects on rock properties, leading to a reduction in rock porosity and permeability. Consequently, it affects the injectivity and storage capacity of the reservoir. In addition, the reliability of fluid-rock reaction simulations is uncertain and requires calibration using laboratory data. However, there is a scarcity of published experimental data on the geochemical effects of CO2-H2S under reservoir conditions. The objective of this study is to measure the key parameters of geochemical reaction kinetics between injected CO2-H2S at 400 ppm concentration level, brine, and carbonate reservoir rocks, and their effects on fluid and rock properties. Carbonate core samples from the X Field have been selected as a case study due to their identification as potential CO2-H2S storage sites, and the availability of the core samples. In this study, H2S gas with a concentration level of 400 ppm is pre-mixed with CO2 and brine water. The CO2-H2S-brine mixture is aged with core samples under X Field reservoir conditions using two different setups: high-pressure chamber (static) and core flood (dynamic) for a duration of 30-days and 14-days respectively. These setups were designed to represent two different scenarios during injection: far from the wellbore and near wellbore scenario. At the end of the ageing period, cores and effluent were collected for analysis to measure changes in key geochemical parameters, including rock porosity, permeability, mineralogy, and images from CT scans, between the post-ageing and pre-ageing stages. The findings offer valuable insights into the behavior and stability of carbonate rocks within near wellbore and far from the wellbore environments during CO2-H2S interactions. Understanding the geochemical processes involved is crucial for evaluating the long-term stability and containment of CO2 or natural gas containing impurities such as H2S in geological storage scenarios.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.66)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Effects of Rock Heterogeneity and Wettability on CO2 Mineralization During Storage in UAE Depleted Carbonate Gas Formations
Fathy, A. (Chemical and Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE) | Adila, A. S. (Chemical and Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE) | Ahmed, S. (Chemical and Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE) | Hassan, A. M. (Chemical and Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE) | Al-Shalabi, E. W. (Chemical and Petroleum Engineering Department, Research and Innovation Center on CO2 and Hydrogen, Khalifa University of Science and Technology, UAE.) | Al Ameri, W. (Chemical and Petroleum Engineering Department, Research and Innovation Center on CO2 and Hydrogen, Khalifa University of Science and Technology, UAE.)
Abstract Anthropogenic CO2 emissions have accumulated significantly in the last few decades aggravating global warming. Mineral trapping is a key mechanism for the global energy transition during which injected CO2 is sequestered within the subsurface formations via dissolution/precipitation. However, the data of CO2 mineralization are extremely scarce, which limits our understanding of suitable candidate formations for mineral trapping. The aim of this study is to emphasize the impacts of wettability and rock heterogeneity on mineral trapping occurring during CO2 sequestration in carbonate formations. In this study, a numerical approach was followed by setting up one-spot pilot test-scale models of homogeneous and heterogeneous carbonate formations to predict the mineral trapping capacity of CO2 gas for two distinct wetting states: Strongly Water-Wet (SWW) and Intermediately Water-Wet (IWW). Accordingly, a 3D Cartesian base case model was created with upscaled petrophysical parameters to mimic the subsurface conditions of a representative carbonate formation from UAE. The study highlighted the relationship between carbonate wettability, rock heterogeneity, and fate of CO2 plume and mineralization potential. In this study, the effect of wettability and heterogeneity were analyzed in terms of CO2 mineralized after 1 year of injection and 200 years of storage. The mineral trapping capacities computed showed a monotonic increase as the wettability shifted from SWW to IWW irrespective of reservoir heterogeneity with different extents. Notably, after 115 years of storage, the heterogeneous formations started to sequester more CO2 attributed to permeability variance increase. In the same context, plume of CO2 extended upwardly and laterally further in case of intermediately water-wet compared to strongly water-wet, especially at earlier stages of storage duration. Classical trapping mechanisms such as solubility trapping gained more attention than mineralization. This is attributed to the time-dependency of mineralization with slow reaction rate scaling up to millennia. Thus, CO2 mineralization potential assessment is important to de-risk large-scale pilot tests. This work provides new insights into underpinning the effects of wettability and rock heterogeneity on CO2 storage capacity in carbonate formations. The findings suggest that mineralization within carbonate immobilizes CO2 and thus, assists in stable and long-term storage.
- North America > United States (1.00)
- Europe (0.94)
- Asia > Middle East > UAE > Sharjah Emirate (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.17)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geochemistry (0.69)
- Geology > Geological Subdiscipline > Geomechanics (0.67)
- Oceania > Australia > Victoria > Bass Strait > Otway Basin > Waarre Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Sleipner Field > Draupne Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/8 > Sleipner Field > Draupne Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Dissolution Behaviors of Naturally Altered Basalts in a Brine at 100 °C for In-Situ CO2 Mineralization
Wang, Jiajie (Tohoku University, Sendai) | Watanabe, Noriaki (Tohoku University, Sendai) | Yagi, Masahiko (Japan Petroleum Exploration Co., Ltd. Research Center) | Tamagawa, Tetsuya (Japan Petroleum Exploration Co., Ltd. Research Center) | Hirano, Hitomi (Japan Petroleum Exploration Co., Ltd. Research Center)
Abstract The use of basaltic formations and existing wells in oil and gas fields for carbon dioxide (CO2) mineralization holds both technical and economic advantages. However, these basaltic rocks have often undergone natural alteration, and their reactivity in CO2 mineralization remains uncertain. To address this knowledge gap, the present study investigated the dissolution behaviors of both altered and unaltered basaltic rocks in a brine that simulating the real reservoir condition with 5 MPa CO2 gas at 100 ℃ through laboratory batch experiments. The experimental results indicate that the reactivity of altered basalt is comparable to that of unaltered basalt, with the former exhibiting faster leaching of Mg compared to the latter within a 15-day period. This can be attributed to the rapid dissolution of smectite, a type of clay mineral present in altered basaltic rocks. Meanwhile, there was no significant decrease observed in the leaching of Ca. It is important to note that the dissolution of basalt in a CO2-rich environment led to the formation of amorphous calcium carbonate (ACC), accompanied by the precipitation of amorphous SiO2, indicating the initial stages of CO2 geological mineralization. Taken together, these results suggest that altered basaltic rocks can also be utilized for CO2 mineralization at moderate temperatures.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
- Asia > Japan > Honshu Island > Akita Prefecture > Yurihara Field (0.99)
- Asia > Indonesia (0.95)
Optimized Acidizing Stimulation Technology Achieves Production Increase in Ultra-High Temperature Carbonate Reservoirs
Dong, Yifan (PetroChina Changqing Oilfield South Sulige Operation Company) | Lei, Yu (PetroChina Changqing Oilfield South Sulige Operation Company) | Jin, Ting (PetroChina Changqing Oilfield South Sulige Operation Company) | Wang, Bo (PetroChina Changqing Oilfield South Sulige Operation Company) | Wang, Johnson (Total E&P Chine) | Zhang, Yong (Baker Hughes)
Abstract Hydrochloric acid is commonly used for carbonatite acidizing. However, it fails to penetrate deep into the reservoir especially in ultra-high temperature reservoirs to create deep etched fractures due to its fast reactivity and strongly dissolve the rock surfaces. Delayed hydrochloric acid systems such as gelled, crosslinked, and emulsified acid system have been employed but still fall short of meeting the requirements. This paper presents the utilization of an ultra-high temperature suitable, super delayed non-hydrochloric acid system for effective acidizing treatments. Comparative laboratory tests were conducted between the super delayed acid system and existing delayed systems (gelled, crosslinked, and emulsified hydrochloric acid systems) at a formation temperature of 360 °F. These tests included core solubility and reactivity experiments, core-flood studies, corrosion rate measurements, and solubility tests using the same acid volume to dissolve the core until the reaction was complete. Core-flood studies utilized the same acid volume and injection rate to create wormholes, followed by CT scans to examine the internal structure. These tests aimed to determine the acid volume, pumping schedule, loading of corrosion inhibitors, and shut-in time required for complete acid reaction. Existing delayed acid systems exhibited limited penetration into the core, with most of the live acid reacting immediately at the core inlet, resulting in inefficient wormhole creation. In contrast, the super delayed acid system demonstrated significantly lower reactivity, which no more than one third of the existing delayed systems. The slow reactivity of the super delayed acid allowed it to flow deeper and react in a controlled manner, facilitating the dissolution of damage and enabling the propagation of effective wormholes. The reduced reactivity of the super delayed system also led to a 50% decrease in treatment acid volume compared to the existing delayed system, as more super delayed acid was utilized to create dominant wormholes rather than being lost in the creation of smaller, branched wormholes. Additionally, the super delayed acid system exhibited lower corrosion rates, requiring only a small amount (no more than 15% of the existing delayed system) of corrosion inhibitor. In conclusion, the super delayed acid system proved more efficient than existing delayed acid systems for stimulating wells in reservoirs with a formation temperature of 360 °F. The acidizing pumping design specific to the super delayed acid system was successfully executed, the well opening for flow after a three-day shut-in period, The treated well achieved over twice the production increase compared to offset wells treated with existing delayed acid systems. The creation of deep penetrated wormholes is a crucial aspect of acidizing stimulation in carbonate reservoirs, particularly in ultra-high temperature reservoirs where conventional methods are inadequate. The super delayed acid system described in this paper successfully addressed this challenge in a 360 °F carbonate reservoir, resulting in a doubling of production. Furthermore, the super delayed acid system is applicable in temperatures up to 500 °F, providing the petroleum industry with a successful solution for acidizing stimulation in ultra-high temperature carbonate reservoirs.
- Asia (0.68)
- North America > United States > Texas (0.28)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Ningxia > Ordos Basin > Changqing Field (0.99)
- (3 more...)
Abstract Acidizing of high-temperature carbonate reservoirs faces many challenges and requires a superior retarded acid system with high thermal stability, controlled reaction rate, and acceptable corrosion profile as compared to lower-temperature formations. In this study, a novel retarded acid system is introduced to address the shortcomings of the available retarded acid systems in the market. The proposed retarded acid system is based on a unique formulation of HCl and the sodium salt of monochloroacetic acid and does not require gelation by a polymer or surfactant or emulsification in diesel. The proposed acid system combines the use of a strong mineral acid (i.e., hydrochloric acid) with sodium monochloroacetate (HCl/SMCA). The acid system benefits from two mechanisms: 1) hindering the fast reaction of HCl and 2) in-situ acid generation by hydrolysis of SMCA towards glycolic acid which provides dissolution capacity for deeper penetration. The hydrolysis of SMCA occurs over time as acid penetrates through the formation. The HCl/SMCA system has an initial pH of 2-3, which significantly reduces corrosion rates at high temperatures. In this study, the dissolution capacity of the acid system was first measured. Then the potential risk of unwanted precipitation of the reaction products was investigated. Finally, the performances of the SMCA system at various formulations were investigated by performing coreflood experiments at high temperatures. The coreflood experiments were conducted at different injection rates to obtain the acid efficiency curve or pore-volume-to-breakthrough (PVbt) curve. Finally, corrosion experiments were conducted at high temperatures using three SMCA formulations. From the dissolution experiments, it was found that the dissolution capacity of the HCl/SMCA acid system, containing only 6 wt% HCl, can be as high as 1 lb CaCO3 scale/gal. It was shown that the reaction products from the calcite dissolution are fully soluble and the chelation by sodium gluconate is the main responsible mechanism. From the coreflood results, it was found that the new HCl/SMCA system can efficiently stimulate limestone formations with no face dissolution. It improves the wormholing performance significantly over HCl acid only and the PVbt decreases from 2.6 to 1 at 130°C. Benefiting from the gentle nature of the acid/SMCA system, tighter formations can be treated at much lower injection rates. CT scan images confirm the favorable wormhole propagation characteristics of the SMCA formulations. It was shown that 60% of the acid capacity remained unused even at very low injection rate, showing the retardation properties of the proposed system. According to the corrosion data, when SMCA used as retarding agent the corrosivity of HCl is decreased and much lower inhibitor concentrations are needed. The new HCl/SMCA system effectively retards initial non-uniform HCl acidizing and adds in-situ acid generation, thereby improving overall the uniformity of the formation acidizing process. This slow-release HCl/SMCA acid system has a low viscosity and less aggressive initial pH, making its use attractive in a broad range of stimulation applications and offering the oilfield industry a high performing and a cost-effective alternative to acid retardation via polymers/surfactants or emulsification in diesel.
- North America > United States > Texas (0.93)
- Asia (0.93)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT The waste repositories or mining activities interfere with the chemical equilibrium of natural underground water, enhancing the hydro-chemical erosion and widening the flow passage, which may lead to serious geohazard. Understanding the evolution of this hydro-mechano-chemical (HMC) coupling process is helpful to the forecast and mitigation of the influence brought by the human activities. This study extends the original DDA method by embedding the discrete seepage network and considering the widening of fracture flow passage by using the finite difference method. After being validated by comparing the numerical results with those of the laboratory test on a single fracture, the extended DDA method is applied to the analysis of a real reactive tailings case. The results agree well with the previous research and laboratory observations. The simulations indicate that the proposed methodology can be applied in the HMC analysis of the reactive transportation in fractured rock masses and promise a wider application in a more comprehensive analysis in the future. INTRODUCTION Understanding the reactive transportation of fluid in fractured stratum has been of interest over the last decades in many engineering disciplines for different kinds of applications, including underground radioactive waste repositories, over-pumping and contamination from industry and agriculture, and other energy engineering projects. With increasing attention being paid to the sustainable development of underground space, more advanced tools and methodologies are required for design, operation, and safety assessments of these human activities to mitigate environmental damage (Molson, Aubertin, & Bussiere, 2012). The reactive transportation in rock mass is a typical multi-field coupling process. Besides moving with the fluid flow in fractured geological materials by convection, the reactive solute or particle in the groundwater system can also be retarded by other physical or chemical mechanisms, such as sorption on fracture surfaces, diffusion in and out of the rock matrix, in-situ stresses, and chemical reactions between the solute and the rock matrix or the fracture walls (Zhao, Jing, Neretnieks, & Moreno, 2011). For instance, the acid mine drainage produces one of the most sever ground water contamination, characterized by low pH and high dissolved concentration of rock minerals, which can erode rock mass and exert significant long-term impact on underground environment. This chemical solution will migrate through different flow paths, including shallow permeable subsurface pathways (for example a porous aquifer), or deeper through bedrock which is usually controlled by flow through fractures. Meanwhile, it is well known that the in-situ stresses must be taken into consideration in underground engineering, especially in the analysis of fractured rock mass. The field stress changes fracture apertures by causing normal closure, opening, or shear dilation, and consequently varies the seepage field (the flow rate and water head in a specific fracture). Combining with the influence of dissolution or precipitation at fracture surface in chemical reaction, makes the reactive transportation in fractured stratum a complicated Hydro-Mechanical-Chemo (HMC) issue.
- Water & Waste Management > Solid Waste Management (1.00)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Power Industry > Utilities > Nuclear (0.34)
ABSTRACT We present a pore-scale numerical modeling study of coupled fluid flow, solute transport, and mineral dissolution/precipitation in 3D fractured carbonate rocks. The injected fluid can dissolve the carbonate and release carbonate ions into the solutions, which react with Ba resulting in barium carbonates (BaCO3) precipitation. Both a simplified fracture and a complex fracture geometry extracted from real shale images are considered. Simulations with a wide range of Pe and Da numbers are carried out to systematically study their effects on dissolution/precipitation patterns and on evolution of fracture geometry, porosity, and permeability. The results show that the coupled physicochemical process is strongly dependent on the Pe and Da. While similar trend of the permeability-porosity variations is obtained for the two fractures at the same Pe and Da numbers, the evolution of fracture morphology is different due to the difference in initial structure heterogeneity and wall roughness. This work reveals the interplay of advection, diffusion, and reaction in determining the fracture evolution and improves our understanding of fluid-mineral interactions in fractures. INTRODUCTION Fractures play an important role in providing preferred flow pathways in low-permeability formations and significantly enhance their permeability. They can improve gas production for shale reservoirs but can also increase the risks for leaking of CO2 from geological storage sites. The fluid-mineral reactions, including dissolution or precipitation, can cause the alteration of porous medium matrix or fracture wall. Particularly, mineral dissolution (precipitation) can increase (decrease) the pore/aperture size and hence the permeability of porous or fractured media. While there have been a lot of studies on mineral dissolution in porous or fractured media considering resultant pore-structure change (Chen, Kang, Viswanathan, et al., 2014; Kang et al., 2014; Kang et al., 2002; Liu & Mostaghimi, 2017; Rasoulzadeh et al., 2020; Starchenko et al., 2016; Verberg & Ladd, 2002; Verhaeghe et al., 2005, 2006), studies on mineral precipitation are much less (Deng et al., 2021; Kang et al., 2005; Kang et al., 2003; Menefee et al., 2020), and studies on coupled dissolution and precipitation are scarce (Chen, Kang, Carey, et al., 2014; Kang et al., 2010). Particularly, there is no high-resolution pore-scale modeling study on coupled dissolution and precipitation in three-dimensional (3D) fractures with evolving fracture geometry to our best knowledge. Consequently, the complex coupled processes including fluid flow, solute transport, dissolution/precipitation, and evolution of pore structure are not well understood.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.47)
Reactive Transport Modeling of Anthropogenic Carbon Mineralization in Stacked Columbia River Basalt Reservoirs
Cao, Ruoshi (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Muller, Katherine A. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Miller, Quin R. S. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | White, Mark D. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Bacon, Diana H. (Energy and Environment Directorate, Pacific Northwest National Laboratory) | Schaef, H. Todd (Energy and Environment Directorate, Pacific Northwest National Laboratory)
Abstract Numerical simulation of CO2 storage in basalts and related reactive lithologies requires modeling complex, coupled hydrologic and chemical processes, including multi-phase flow and transport, partitioning of CO2 into the aqueous phase, and chemical interactions with aqueous fluids and rock minerals. We conducted reactive transport simulations of the Wallula pilot-scale CO2 injection into the flow tops of the Grande Ronde Basalt using our Pacific Northwest National Laboratory STOMP-CO2 simulator with the ECKEChem reactive module. Our mineralization simulation of the ∼1,000 tons of injected CO2 into the interflow zones was based on the hydrologic transport model we previously developed. For this work, the simulations considered geochemical reactions involving the basalt components, precipitates, formation brine, and injected CO2. In our benchmark case, carbonate minerals precipitated, resulting in ∼20% of the CO2 being mineralized in 10 years. Increasing the reaction rate of a single primary mineral phase (clinopyroxene) by an order of magnitude resulted in a carbon mineralization reaction extent of ∼90% over the same time interval. Based on these initial sensitivity analysis results, it is clear that a thorough understanding of primary mineral dissolution rates is required for accurately predicting long-term fate and transport of injected CO2 into basalt formations. Our reactive transport numerical simulations will be key components of commercial-scale CO2 storage operation permitting, de-risking, and optimization in mafic and ultramafic reservoirs. Introduction In 2009, the Wallula Basalt Pilot project was initiated with the drilling of a CO2 injection well to a depth of 1,253 m below ground level (bgl) at the Boise White Paper Mill property at Wallula, Washington. The well intersected three deep layered basalt flowtops starting at 830 m (Figure 1) that received ∼1,000 tons of CO2 in August of 2013 over three weeks. After 24-month, sidewall cores were extracted from the injection zone as part of an extensive post-injection characterization champaign. Laboratory analysis performed on the retrieved core identified anthropogenic carbonate mineral assemblages (e.g. ankerite, aragonite, and siderite) that were isotopically, texturally, and chemically linked to the injected CO2 (Depp et al., 2022; McGrail et al., 2017a; McGrail et al., 2017b; Polites et al., 2022). Recently, our detailed analysis of pre-injection and post-injection hydrologic testing in the context of a robust hydrogeologic Wallula model indicated that ∼60% of the injected CO2 mineralized in only two years (White et al., 2020). The objective of this present study is to numerically simulate the CO2 transport and reactivity at Wallula and determine how predicted carbon mineralization rate determinations compare with our recent carbon mineralization quantification (White et al., 2020), laboratory results, and field data.