About

Professor Berna Hascakir leads the Hascakir Research Group, serving as the principal investigator. She is actively involved in undergraduate and graduate advising, currently mentoring 4 undergraduate students and 10 graduate students, including 6 PhD, 2 MS, and 2 MEng candidates. Over her career, she has completed advising for 36 undergraduate students and graduated 9 PhD, 17 MS, and 3 MEng students. Additionally, Professor Hascakir has guided 20 professional students, interns, and residents, and continues to mentor 2 PhD-level faculty members outside of student advising. Her committee involvement extends to serving on 18 PhD committees, including 3 outside her department at Texas A&M and 6 international or outside Texas A&M, as well as 15 MS committees and 2 MEng committees. This extensive mentoring and committee service highlights her commitment to academic leadership and fostering research development across multiple levels of higher education.

Research topics

• Petroleum engineering
• Geology
• Waste management
• Environmental science
• Engineering
• Environmental engineering
• Environmental planning
• Organic chemistry
• Chemistry
• Chemical engineering

Selected publications

• Machine Learning-Enhanced In-Situ Combustion: Correcting Carbonate-Derived CO2 Emissions and Evaluating Mineral-Based Carbon Capture

  SPE International Conference on Oilfield Chemistry · 2025-04-02 · 10 citations

  articleSenior author

  Abstract In-situ combustion (ISC) is a well-established enhanced oil recovery (EOR) technique, traditionally used for high-viscosity oil reservoirs. However, its application to low-viscosity oil reservoirs presents challenges due to the high ignition temperature required and insufficient heavy oil fractions to sustain combustion. This study investigates ISC feasibility in a U.S. reservoir by conducting three combustion experiments—two wet and one dry—using rock samples from three different wells to capture reservoir heterogeneities in combustion performance. X-ray diffraction (XRD) analysis showed that around 45 wt% of the reservoir rock consists of dolomite and calcite, leading to significant carbonate decomposition at elevated ISC temperatures, which increases CO2 emissions and complicates traditional ISC stoichiometric models. Recognizing that existing analytical models fail to account for CO2 from rock decomposition, we developed an integrated approach combining combustion tube experiments with thermogravimetric analysis (TGA) and machine learning (ML). A total of 5,748 TGA data points were collected for calcite and dolomite decomposition at multiple heating rates. Two ML models—Random Forest and XGBoost—were trained (80% of data) and tested (20%) to predict CO2 release from carbonates during ISC. Additional TGA experiments on pure calcite and dolomite confirmed that carbonate decomposition begins as low as 350–400°C, significantly earlier than the commonly reported 550–600°C, especially at higher heating rates (15–20°C/min) under air injection. XGBoost outperformed Random Forest, achieving a higher test R² of 0.986 and a lower RMSE of 0.5044 compared to R² of 0.9846 and RMSE of 0.5289 for Random Forest. Applying ML-based corrections to ISC models significantly improved the accuracy of combustion parameter calculations. The updated model corrected the main combustion reactions, accurately estimating energy generated by crude oil burning (~15,000 BTU/lbm) and energy consumed by carbonate decomposition (~3,000 BTU/lbm). Since CO2 emissions limit ISC applicability, we also explored real-time carbon capture by installing natural mineral filters composed of olivine, dolomite, and ultramafic rock at the combustion tube outlet. These filters were exposed to flue gases for 6.7 hours, achieving measurable carbon uptake of 2.39–7.81 mg carbon per 100 mg sample. Despite the absence of XRD peaks, our results strongly indicate the formation of amorphous MgCO3 or a related carbonate phase on the filter surfaces, as supported by Energy Dispersive X-ray Spectroscopy (EDS), Thermogravimetric Analysis (TGA), and Fourier Transform Infrared (FTIR) spectroscopy results. It underscores the role of mineral-based filtration in ISC carbon mitigation, relying on surface interactions rather than bulk mineral carbonation. These findings highlight the significant impact of rock-derived CO2 on combustion stoichiometry and demonstrate the potential of mineral-based carbon capture for reducing ISC emissions. Implementing zero-emission ISC strategies could enhance the feasibility of this technology for carbonate-rich light oil reservoirs.

  PublisherDOI

• The Impact of Permeability and Porosity on In-Situ Combustion Performance in Bakken Formation

  SPE Annual Technical Conference and Exhibition · 2025-10-13 · 5 citations

  articleSenior author

  Abstract In-situ combustion (ISC) is a thermal enhanced oil recovery (EOR) process traditionally deployed in conventional reservoirs. Its applicability to unconventional, ultra-low-permeability reservoirs remains largely untested, due in part to the challenges of initiating and sustaining combustion within restricted flow environments. This study presents a systematic investigation of ISC dynamics in tight Middle Bakken Formation, emphasizing the effects of initial permeability and porosity on combustion performance, oil recovery, and rock properties alteration. Two laboratory-scale dry in-situ combustion tube experiments were conducted using compacted mixtures of Middle Bakken cuttings, brine, and crude oil. The first experiment, referred to as E1, was loosely packed to achieve a baseline average permeability of 10.72 mD and porosity of 40.65%. The second experiment, E2, was tightly packed to simulate lower permeability conditions, with an initial permeability of 0.70 mD and porosity of 20.21%. Both systems were subjected to an identical air injection pressure of 85 psi and backpressure of 40 psi, and air injection rate of 5.5 SLPM with continuous measurement of temperature propagation, gas composition, and fluid recovery. Despite the significant disparity in initial permeability, both systems maintained a stable and self-sustaining combustion front. The tightly packed E2 system demonstrated a higher average front velocity of 21 ft/day and achieved an oil recovery of 78.9 % of the original oil in place (OOIP). In contrast, E1 showed a slower front velocity at 16 ft/day and recovered 71.5 % of OOIP. Gas analysis revealed high combustion efficiency in both cases, with strong oxygen consumption and substantial carbon dioxide production. E2 additionally exhibited cyclic oxygen–carbon dioxide fluctuations, indicative of packing-induced heterogeneity and evolving flow paths. Post-ISC X-ray computed tomography scans revealed fundamentally different alteration mechanisms. E1 exhibited localized fracturing near the ignition zone, whereas E2 showed pervasive micro-fracturing and distributed matrix decomposition. The results from E2 underscore ISC ability to enhance flow capacity in Middle Bakken rock sample not solely through combustion but also via thermal stress-driven microstructural changes. The confined geometry of the tight packing amplified temperature gradients and induced grain-scale cracking across the matrix, thereby improving connectivity and enabling sustained front propagation. These changes resulted in a twofold increase in porosity and a fifteenfold increase in permeability for the tight system, effectively transforming it into a more conductive medium. Collectively, these results validate ISC as a viable and potentially transformative EOR technique for unconventional reservoirs, demonstrating its ability to simultaneously mobilize hydrocarbons and enhance in-situ rock permeability under tight conditions. The significant porosity and permeability gains observed, particularly in the tight-packed system, underscore ISC's potential to unlock bypassed oil by thermally upgrading the reservoir matrix. These outcomes establish a strong experimental foundation for future ISC deployment in low-permeability, organic-rich formations.

  PublisherDOI

• Dielectric and Thermal Characterization of Reservoir Rocks for In-Situ Hydrogen Production Via Microwave Heating

  SPE Annual Technical Conference and Exhibition · 2025-10-13

  articleSenior author

  Abstract This study investigates how dielectric properties, mineral composition, and fluid saturation influence microwave energy absorption, temperature rise, and hydrogen yield in reservoir rocks from the Permian Basin. We specifically examine the role of calcite content in enabling or inhibiting hydrogen production, even when the hydrocarbon source is identical. The aim is to establish dielectric testing as a predictive tool and to identify mineralogical parameters—particularly calcite—that directly impact hydrogen generation under microwave irradiation. Three core samples were characterized using X-ray diffraction (XRD), thermogravimetric analysis/differential scanning calorimetry (TGA/DSC), and dielectric property measurements with a Vector Network Analyzer (VNA) at 2.45 GHz. Direct microwave heating experiments were performed on both air-saturated rocks and fluid-saturated systems containing identical crude oil and brine compositions. Six total experiments were conducted: three on dry rocks (E1-0, E2-0, E3-0) and three on rock–oil–brine blends (E1-1, E2-1, E3-1). An additional test (E2-2) was performed by manually adding 10 wt% calcite to the intermediate-calcite rock to examine its effect on hydrogen production. Gas yields and temperature profiles were continuously monitored. VNA results revealed strong positive correlations between total organic content and both dielectric constant and loss index, confirming that organic matter significantly enhances microwave absorption. Direct heating experiments showed that hydrogen generation only occurred in fluid-saturated systems reaching sufficiently high temperatures. Rock 1 (negligible calcite) and Rock 3 (∼24 wt% calcite) produced hydrogen despite different maximum temperatures—2000 °C for Rock 1 and ∼950 °C for Rock 3. Surprisingly, Rock 2, which had intermediate calcite content (∼9 wt%), produced no hydrogen in two separate trials, despite using the same crude oil and brine. To investigate this inhibition effect, we blended Rock 2 with 10 wt% additional calcite (E2-2). This mixture reached ∼650 °, higher than the original Rock 2 blend (∼350 °C), and successfully produced hydrogen. The results suggest that calcite decomposition to CaO can promote hydrocarbon cracking reactions, particularly in the presence of other mineral phases, enabling hydrogen generation even at lower peak temperatures. These findings indicate that dielectric measurements can serve as a rapid screening method for predicting heating performance, while calcite content directly influences catalytic pathways for hydrogen production.

  PublisherDOI

• First In-Situ Combustion Test in the Permian Basin

  2025-11-18 · 5 citations

  articleSenior author

  Abstract Hydraulic fracturing in the Permian Basin typically recovers only 8–12% of the original oil in place, leaving large volumes of hydrocarbons untapped. This study investigates in-situ combustion (ISC) as an alternative enhanced oil recovery (EOR) method, with particular emphasis on the role of rock and brine in enabling combustion sustainability in light-oil systems. Unlike re-fracturing, ISC establishes a self-sustained thermal drive that can mobilize bypassed oil and alter reservoir properties. A one-dimensional combustion tube experiment was performed using crushed Permian rock saturated with crude oil and formation brine (50:50 volumetric ratio). Ignition was achieved at 350 °C, and a stable combustion front propagated at ~1.2 m/day (≈4 ft/day) with sustained temperatures near 650 °C. Gas analysis confirmed efficient oxygen utilization and continuous carbon dioxide production, with only minor carbon monoxide and methane detected. These results are notable given the light nature of the oil (7.44 cP at 20 °C, negligible asphaltenes), suggesting that mineral and brine interactions were key contributors to ignition and combustion stability. Produced fluids further highlighted these interactions. Formation brine salinity decreased from 69,400 ppm to ~45,000 ppm, with modest pH reduction, indicating salt precipitation and partial acidification that can mitigate scaling risks. Produced oil viscosity decreased from 7.44 cP to 4.87 cP at 20 °C, confirming thermal upgrading without emulsion formation. Postmortem analyses revealed distinct zonation along the combustion tube. Energy Dispersive Spectroscopy (EDS) and Fourier Transform InfraRed (FTIR) analysis indicated carbonate decomposition, coke deposition, sulfur retention as Ca–S phases, hematite formation, and localized Na–Cl deposition in the heater zone. These mineralogical and geochemical transformations demonstrate that both rock and brine actively sustain ISC by providing reactive surfaces, capturing combustion byproducts, and contributing to consolidation in burned regions. This study provides the first experimental evidence that ISC is feasible in Permian shale under realistic rock–fluid conditions. The findings establish ISC as a technically viable, cost-effective, and environmentally sustainable alternative to re-fracturing, and they highlight the critical role of rock–brine–gas coupling in driving combustion in light-oil reservoirs. Collectively, these results offer a strong foundation for future pilot-scale ISC applications in the Permian Basin.

  PublisherDOI

• Wet In-Situ Combustion Substantially Increases Oil Recovery in Light Oil Shale Reservoirs

  SPE Annual Technical Conference and Exhibition · 2025-10-13 · 2 citations

  articleSenior author

  Abstract This study presents a novel application of in-situ combustion (ISC) for enhancing oil recovery in light oil shale reservoirs, using core materials and fluids from the Bakken Formation. ISC is a well-established thermally enhanced oil recovery (EOR) method, traditionally applied to heavy oil reservoirs. This study explores its potential for shale oil plays, a concept that has received limited investigation in U.S. shales. ISC enhances sweep efficiency, maximizes oil recovery, and lowers operating costs, making it a promising technique for U.S. shale reservoirs. We conducted five experiments using a 1-meter-long insulated stainless steel combustion tube packed with Bakken crushed reservoir rock, formation brine, and low-viscosity crude oil at a 1:1 liquid pore volume ratio. Compressed air injection into a preheated tube initiated combustion. Dry ISC relied solely on air injection, whereas during wet ISC, we co-injected air and distilled water at controlled water-to-air ratios. We used three shale samples, two oil-wet and one non-oil-wet, from different Bakken formation wells. Fourier-transform infrared spectroscopy (FTIR) and thermogravimetric analysis with differential scanning calorimetry (TGA-DSC) quantified residual hydrocarbons and water. We applied the Sarathi (1998) and Nelson and McNeil (1961) analytical models to evaluate ISC performance for field-scale implementation. Results showed that rock mineralogy and wettability strongly influenced ignition behavior, with oil-wet shale igniting at 183 °C and non-oil-wet rock requiring up to 350 °C. Wet ISC consistently produced a more stable combustion front, reduced oxygen breakthrough, and enhanced thermal efficiency. Front velocities increased from 10.5 ft/day (dry) to 15.1 ft/day (wet), with significantly lower air injection needs. FTIR and TGA-DSC confirmed near-complete hydrocarbon removal in wet modes. Analytical modeling demonstrated higher oxygen utilization (88–92%) and 40–50% lower power and air demand for wet ISC compared to dry ISC. This study introduces dry and wet ISC as a viable approach for shale oil reservoirs, offering high efficiency and cost-effectiveness as an EOR method. Enhanced combustion stability and substantial oil recovery make ISC well-suited for shale formations. These findings pave the way for wet ISC implementation in U.S. shale reservoirs, providing a scalable and sustainable solution for improving oil recovery while minimizing operational costs.

  PublisherDOI

• Hydrogen at the Source: Unlocking Clean Energy from Bitumen with Advanced Thermal Recovery

  2025-09-01 · 2 citations

  articleSenior author

  Abstract This study investigates the feasibility of generating hydrogen directly from various crude oil types—ranging from light and waxy oils to bitumen—using both microwave-assisted combustion and conventional combustion methods. The objective is to evaluate the efficiency of each approach and assess the potential to convert diverse petroleum resources into hydrogen while enabling in situ retention of carbon-rich byproducts (e.g., CO2, CH4), offering a novel low-emission pathway for energy transition. Laboratory-scale pseudo-reservoirs were prepared by mixing crude oil and brine (50:50 pore volume) with Ottawa sand and packing the blends into core holders. The tested oils varied widely in physical properties, with API gravities from 4.5 to 52 and viscosities between 4 cP and 178,500 cP. Thermal stimulation was applied using either microwave assisted or conventional combustion with continuous air injection, and real-time temperature profiles were recorded. Gas samples were collected and analyzed using gas chromatography (GC), with a focus on hydrogen, carbon dioxide, carbon monoxide, methane, and other gaseous products. Results from five experiments showed that hydrogen production occurs only when oxygen is present and is highly influenced by heating rate and oil composition. Microwave-assisted combustion consistently achieved earlier gas evolution and produced higher hydrogen yields, particularly from heavier oils such as bitumen. Fourier Transform InfraRed (FTIR), dielectric property, and Thermogravimetric Analyzer and Differential Scanning Calorimetry (TGA/DSC) analyses confirmed that both molecular structure and the presence of polar compounds and clay minerals enhance microwave absorption. These findings demonstrate that microwave-assisted combustion offers a promising approach for subsurface hydrogen generation, enabling selective gas production while retaining unwanted byproducts underground, contributing to cleaner energy recovery strategies.

  PublisherDOI

• Thermal Treatment Innovations for High-TDS Produced Water: A Multidisciplinary Path to Sustainable Reuse

  2025-11-18

  article1st authorCorresponding

  Abstract Produced water (PW) from hydraulic fracturing is one of the most challenging waste streams in the oil and gas industry due to its high salinity, complex chemistry, and large volumes. This study evaluates innovative thermal approaches for treating high-TDS PW by combining detailed geochemical characterization with evaporative cooling (EC) and in-situ combustion (ISC) experiments and compares these results with chemical precipitation screening. PW samples from 15 wells in the Permian Basin and one from the Williston Basin were characterized using ion chromatography (IC) and inductively coupled plasma–mass spectrometry (ICP-MS). EC experiments were conducted on representative samples from the Delaware, Northern Midland, and Southern Midland sub-basins to assess TDS removal, recovery volumes, and the impact of suspended solids. Silver nitrate (AgNO3) screening was used to test halide precipitation and turbidity reduction. ISC experiments were performed on a Permian Basin sample (dry ISC) and a Williston Basin sample (wet ISC), and the effluents were analyzed for TDS, pH, gas composition, and rock surface chemistry using energy-dispersive spectroscopy (EDS). Characterization showed TDS values ranging from ~41,000 to 200,000 ppm, with Na+ and Cl- as the dominant ions, and lithium consistently present at 10–100 ppm as the fourth most abundant element. AgNO3 precipitation produced clear supernatants and reduced turbidity, but bulk TDS removal was negligible. EC achieved complete (100%) TDS removal at an estimated operational cost of USD 3–6 per barrel (excluding infrastructure), although treated water recovery decreased with increasing salinity and suspended-solids pretreatment offered no benefit. In ISC, the Permian test reduced TDS from ~70,000 to ~45,000 ppm at >600 °C without acidification and showed limited NaCl deposition, consistent with the sample's mixed-salt composition. By contrast, the Williston wet ISC test achieved nearly complete desalination (120,000 → 100 ppm TDS), a pH increase from 5.15 to 8.00, and significant halite deposition on the rock matrix. These results demonstrate that thermal methods, particularly ISC, provide viable and scalable pathways for managing high-TDS produced water. EC offers a low-cost surface treatment option, while ISC is most effective in NaCl-rich brines, where in-reservoir salt capture enables substantial desalination alongside energy recovery. The consistent presence of lithium further underscores the dual opportunity of treating produced water and recovering critical minerals, advancing multidisciplinary strategies for sustainable water management in the oil and gas industry.

  PublisherDOI

• Mechanistic Insights into Microwave-Assisted Hydrogen Generation from Crude Oils: Influence of Polarity, Dielectric Properties, and Clay Minerals

  SPE Annual Technical Conference and Exhibition · 2025-10-13 · 1 citations

  articleSenior author

  Abstract This study aims to evaluate the efficiency of microwave-assisted combustion for in-situ hydrogen production from crude oils with varying compositions, focusing on the role of crude oil polarity, particularly resins-to-asphaltenes ratios, and lithological interactions. Special emphasis is placed on understanding how dielectric properties and the presence of mineral phases, such as clays, influence hydrogen yields, gas composition, and thermal behavior compared to conventional combustion. Four crude oils spanning a wide viscosity range were characterized via SARA (Saturates, Aromatics, Resins, Asphaltenes) analysis and dielectric property measurements. Pseudo-reservoir systems were prepared by mixing oil, water (50:50), and crushed Permian Basin reservoir rock. Microwave heating (2.45 GHz, 1200 W) was applied, and gas compositions were continuously monitored by gas chromatography. Control experiments with conventional heating were conducted for comparison. Additional runs incorporating 5 wt% clay into Oil 1 and Oil 4 were performed to evaluate mineral effects on hydrogen generation and reaction pathways. Microwave-assisted combustion produced measurable hydrogen in all crude oil systems, whereas conventional heating yielded no detectable hydrogen despite higher overall oil-to-gas conversion. Hydrogen yield trends were: Oil 3 (Waxy Oil) > Oil 4 (Light Oil) > Oil 1 (Bitumen) > Oil 2 (Extra-Heavy Oil), aligning with higher polar content and favorable resins-to-asphaltenes ratios. Oils with strong resin–asphaltene interactions exhibited reduced microwave coupling efficiency despite high polar content. Dielectric measurements revealed that crude oil loss tangent correlated strongly with resins-to-asphaltenes ratios (R2 = 0.9949), indicating that polarity balance, not just magnitude, governs microwave absorption. When mixed with rock and water, loss tangent values converged (~0.29), but dielectric constant differences still influenced thermal and gas production performance. Clay addition significantly enhanced hydrogen yields and total gas conversion for Oil 1 and Oil 4, even when maximum temperatures were lower than clay-free cases. This enhancement is attributed to a secondary hydrogen generation pathway, potentially involving microwave-activated clay–bound water–methane reforming. Correlation analysis showed CO generation tracked with hydrogen yield (R2 = 0.8709), likely via reforming and water–gas shift reactions, while CH4 and C2H4 production were closely linked (R2 = 0.9204), consistent with parallel cracking pathways. Clay reduced CH4 and C2H4 production at high hydrogen yields, suggesting pathway selectivity toward reforming over cracking. This work provides the first integrated mechanistic assessment of microwave-assisted hydrogen generation from crude oils, linking molecular polarity, dielectric properties, and mineral-phase effects. By demonstrating that clay can simultaneously enhance hydrogen yields and suppress undesired hydrocarbon cracking products, the study identifies a tunable pathway for selective hydrogen production. The findings offer a scalable, low-emission strategy for in-situ hydrogen generation from petroleum reservoirs, with implications for clean energy recovery in both conventional and unconventional systems.

  PublisherDOI

• Feasibility and Efficiency of Dry and Wet In-Situ Combustion in Low-Viscosity Oil Reservoirs

  SPE Western Regional Meeting · 2025-04-25 · 7 citations

  articleSenior author

  Abstract In-situ combustion (ISC) is a complex thermal enhanced oil recovery (EOR) method traditionally applied to heavy and extra-heavy oil reservoirs. Its application to low-viscosity oil reservoirs presents challenges due to the higher ignition temperature requirements, resulting from the stable molecular content of such oils, and the lack of heavy fractions, such as asphaltenes and resins, which serve as fuel for sustaining combustion fronts. This study investigates low-viscosity oil combustion mechanisms and examines the interactions between reservoir rock, brine, and crude oil in sustaining combustion fronts during dry and wet ISC processes. The experiments utilized a 1-meter-long insulated stainless steel combustion tube packed with a mixture of reservoir rock, formation brine, and low-viscosity crude oil at a 1:1 liquid pore volume ratio. Combustion was initiated by injecting compressed air into the preheated tube. Dry ISC experiments involved air injection alone, while wet ISC co-injected air with distilled water at specific water-to-air ratios (WAR). The tested reservoir rocks included quartz-rich Canadian sand (Sample 1), U.S. reservoir rock 1 (Sample 2), and U.S. reservoir rock 2 (Sample 3). Post-experiment analyses were performed using Scanning Electron Microscopy with Energy Dispersive Spectroscopy (SEM-EDS) to evaluate elemental composition and mineral transformations. The water produced was analyzed for pH and Total Dissolved Solids (TDS). Results emphasize the crucial role of reservoir rock reactivity and brine ionic strength in sustaining combustion fronts in low-viscosity oil reservoirs. Dry ISC led to less stable fronts, with peak temperatures ranging from 550 to 600°C, whereas wet ISC exhibited superior performance, achieving stable combustion fronts, higher combustion velocities, and lower peak temperatures. Produced water analyses indicated a salinity reduction from 120,000 ppm to as low as 30 ppm, supporting its feasibility for re-injection. Additionally, wet ISC resulted in cleaner reservoir rocks with minimal carbon residues, underscoring its advantages in efficiency, stability, and operational feasibility over dry ISC for low-viscosity oil recovery. This study provides a novel approach to ISC in low-viscosity oil reservoirs, demonstrating that despite the high ignition temperature requirement, reservoir rock and brine interactions play a key role in sustaining combustion. Unlike conventional ISC studies that focus on heavy oil, this research highlights how wet ISC can significantly enhance combustion stability and efficiency in low-viscosity oils, where conventional fuel sources (asphaltenes and resins) are insufficient. Furthermore, the study introduces the re-injection of treated produced water as a sustainable method to improve ISC efficiency, minimize environmental impact, and reduce operational costs. These findings offer new insights into optimizing ISC for low-viscosity oil reservoirs, making it a more viable and eco-friendly thermal EOR technique.

  PublisherDOI

• Ultramafic Rock-Based Filters for CO2 Capture in Simulated Emission Streams: An Experimental Approach with Combustion Cells

  2025-09-01 · 1 citations

  articleSenior author

  Abstract This study explores the carbon capture and mineralization potential of ultramafic rock powders when exposed to flue gases generated from combustion of a crude oil and mesquite-derived charcoal. Three ultramafic rock samples—designated as Samples 20, 22, and 26—were characterized using Fourier Transform Infrared (FTIR) spectroscopy and thermogravimetric/differential scanning calorimetry (TGA/DSC) before and after exposure to flue gases. The samples were placed in stainless steel filter housings downstream of a heated combustion cell designed to simulate industrial CO2-emitting sources. Flue gas compositions were monitored in real-time using gas analyzers and gas chromatography, with bypass lines used as control conditions. FTIR analyses of post-exposure samples revealed the emergence of broad O–H stretching bands (~3300 cm-1), asymmetric CO2 vibrational modes (~2358–2332 cm-1), and a dominant carbonate peak at ~873 cm-1, indicating successful capture and partial mineral transformation of CO2. Despite extensive toluene washing and thermal drying at 50 °C, these spectral features persisted, suggesting chemisorption or irreversible physical adsorption of CO2 onto the rock surfaces. Notably, Sample 26, which was least exposed to condensable hydrocarbons, exhibited the clearest CO2 signatures. Following flue gas exposure, samples were subjected to TGA/DSC under air at 10 °C/min up to 900 °C. Post-heating FTIR spectra showed the disappearance of OH- and H2O-related bands and the preservation of the carbonate peak near 873 cm-1, indicating thermally stable amorphous carbonate formation. In contrast, OH-rich clay signals present in the initial samples disappeared after heating, suggesting dehydroxylation and phase transformation. Among the samples, Sample 22 exhibited the highest normalized mass gain and most robust carbonate signature, likely due to its mineralogy, which includes serpentine, olivine, dolomite, and talc. These findings confirm that ultramafic rocks can serve as both physical CO2 adsorbents and reactive mineral filters capable of capturing and stabilizing carbon in solid form under flue gas exposure.

  PublisherDOI

Frequent coauthors

• Taniya Kar

  Reservoir Engineering Research Institute

  43 shared

• Norasyikin Ismail

  Universiti Malaysia Pahang Al-Sultan Abdullah

  32 shared

• Abhishek Punase

  Clariant (Switzerland)

  30 shared

• Matthew Morte

  Texas A&M University

  28 shared

• Albina Mukhametshina

  Texas A&M University

  24 shared

• Tanya Ann Mathews

  Texas A&M University

  23 shared

• Andreas Prakoso

  Mitchell Institute

  23 shared

• Sudiptya Banerjee

  Texas A&M University

  21 shared

Education

• Postdoc, Energy Resources

  Stanford University

  2010

• PhD, Petroleum and Natural Gas Engineering

  Orta Doğu Teknik Üniversitesi

  2008

• Visiting PhD Student, DEPARTMENT OF CIVIL AND ENVIRONMETAL ENGINEERING SCHOOL OF MINING AND PETROLEUM ENGINEERING

  University of Alberta

  2008

• MSc, Environmental Technologies

  Dokuz Eylül Üniversitesi

  2003

• BSc, Environmental Engineering

  Dokuz Eylül Üniversitesi

  2001

Awards & honors

• Distinguished Member, Society of Petroleum Engineers – 2018
• Leadership Development Program ADVANCE Administrative Fellow…
• Flotek Industries, Inc. Career Development Professor, Texas…
• Stephen A. Holditch Faculty Fellow, Texas A&M University – 2…
• Innovative Teaching Award, Society of Petroleum Engineers –…