About

Professor Abbas Firoozabadi leads research focused on the very large-scale use of CO2 from different sources to prevent its emission into the atmosphere. His work includes the production of renewable geothermal energy from the subsurface and waterless fracking of subsurface formations for various applications. Additionally, his research investigates the reinjection of high salt content brine into subsurface formations to improve oil recovery. A significant aspect of his research involves engineering molecules that viscosify CO2 at low concentrations, facilitating CO2 sequestration and controlling its mobility to prevent leakage. This viscosification process helps keep CO2 in the subsurface, enhancing process efficiency and safety. Professor Firoozabadi's major research activities encompass molecular engineering, including functionalization and molecular simulations, as well as equilibrium and irreversible thermodynamics, thermodynamics of deformable materials, and fluid-solid interfaces. He also focuses on large-scale simulation of subsurface fluid flow, porous media deformation, and crack propagation, emphasizing higher-order numerical methods integrated with thermodynamic concepts. His work extends to flow assurance topics such as hydrate anti-agglomeration, fluid-fluid interfacial elasticity, fluid-solid interfacial energy density, hydraulic fracturing by water and CO2, and kerogen swelling.

Research topics

• Organic chemistry
• Materials science
• Geology
• Thermodynamics
• Chemical engineering
• Chemistry
• Composite material
• Petroleum engineering
• Chromatography

Selected publications

• Synergy of Polymer Mobility Control and Surfactant for Interface Elasticity Increase in Improved Oil Recovery

  SPE Journal · 2025-07-29 · 2 citations

  articleSenior author

  Summary The injection of modified brines is one of the most studied improved oil recovery (IOR) methods for sandstone and, more recently, carbonate reservoirs. Examples include low-salinity waterflooding, surfactant injection for residual oil reduction, and polymer injection to improve sweep efficiency. Polymer addition to injection water has had many field successes. Polymer and surfactant injections are often effective, but 2,000–10,000 ppm concentrations may make the processes expensive. We have recently suggested the idea of an ultralow concentration of polymeric surfactants (PSs) at 100 ppm to decrease residual oil saturation (ROS) from increased brine-oil interface elasticity. This work investigates the synergistic effect of polymers for sweep efficiency and the increase in interfacial elasticity with PSs. The combined formulation may provide both sweep efficiency and residual oil reduction. The effect of polymer on ROS is also examined in our investigation. Coreflooding tests are performed on carbonate rocks using four crude oils and a variety of aqueous injection fluids—two high-salinity brines combined with a nonionic PS and two different polymers. Polymers are found to improve recovery at breakthrough via the increase in injection brine viscosification. They may reduce or increase ROS. The PS promotes higher final recovery by increasing the interfacial oil-brine elasticity. When using both a PS and a polymer, breakthrough is delayed, and final recovery is improved compared with polymer alone. Oil recovery may be a strong function of oil-brine interfacial viscoelasticity in polymer flooding.

  PublisherDOI

• Enhanced viscosification of supercritical CO2 by a new polyolefin copolymer: Insights from solubility and displacement of brine and oil in porous media flow

  International journal of greenhouse gas control · 2025-10-01 · 2 citations

  articleSenior authorCorresponding
  PublisherDOI

• Temperature-Dependent Mechanical Properties of Geo-Materials: Insights from Molecular Dynamics Simulations

  The Journal of Physical Chemistry C · 2025-08-21

  articleSenior authorCorresponding

  The mechanical properties of geo-materials play a critical role in hydrocarbon extraction and geothermal energy development. The thermal response of many geo-materials’ elastic properties remains unclear. We conduct molecular dynamics (MD) simulations to investigate the temperature dependency of mechanical properties of geo-materials, including kerogen, quartz, illite, and calcite. Young’s modulus, Poisson’s ratio, shear modulus, and critical stress are systematically evaluated at different temperatures and crystallographic orientations. The simulations indicate that increasing temperature leads to a pronounced reduction (over 50%) in Young’s and shear moduli for kerogen. Illite exhibits a clear decline (30%) in Young’s modulus due to its layered structure, which contributes to anisotropic deformation. Young’s and shear moduli of quartz have a mild decrease with temperature. Calcite displays intermediate declines of about 10% in Young’s modulus in the X and Z directions and 6% decrease in the Y direction. The shear modulus of calcite decreases by 7% in the X and Z directions, and by 15% decrease in the Y direction. Poisson’s ratio remains largely invariant for the materials we have examined, indicating a consistent volumetric deformation response despite temperature changes. All geo-materials in this study exhibit a decreasing trend in critical stress with increasing temperature. These findings provide key insights into the thermo-mechanical stability of geo-materials, particularly in high-temperature environments. Our work sets the basis for the investigation of the cross effect neglected in the classical relationship between stress and strain in solid mechanics.

  PublisherDOI

• Does Interfacial Viscoelasticity Increase Oil Recovery at High Temperature and Salinity in Carbonates?

  SPE Journal · 2025-03-24 · 2 citations

  articleSenior author

  Summary Low salinity water (LSW) injection may increase oil recovery in some crude oils. Despite the general belief that the mechanism of LSW is governed by wettability alteration, crude oil-water interfacial viscoelasticity appears to have a more dominant effect on oil recovery. The elasticity of the crude oil-water interface may be tuned by a very small amount of a polymeric surfactant (PS). In this work, we present a systematic investigation of viscoelastic interfaces in different crude oil-brine systems using four different crude oils (A, B, C, and D). The interfacial elasticity is measured for crude oil-LSW, crude oil-high salinity water (HSW), and crude oil-HSW with 100 ppm PS (HSW-PS). The measurements are conducted by shear oscillations of the interface at 25°C and atmospheric pressure. The PS may increase the elasticity of the crude oil-water interface significantly. Three of the crude oils (A, C, and D) show an increase in interface elasticity with 100 ppm PS in HSW. In one crude oil (B), there is no appreciable change in interface elasticity for HSW, LSW, and HSW-PS. We have conducted 15 different coreflooding experiments in carbonate rocks. Six experiments are carried out at 50°C, two at 90°C, and another five at 100°C. Experiments are conducted using stock-tank crude oil and formation water of very high salinity. We conduct two additional experiments at 100°C using live crude oil. The overall observation is that there is extra recovery from the addition of 100 ppm of PS to HSW injection. The extra recovery is in the range of 8–20% for oil displacement by the aqueous phase with high interfacial elasticity promoted by the addition of 100 ppm PS in HSW. The oil recoveries are found to be greater at high temperatures during the displacements of both stock oil and live oil with the use of 100 ppm of PS. Interface elasticity measured at 25°C may provide an indication of extra recovery at high temperatures.

  PublisherDOI

• Numerical Simulation of Hydraulic Fracturing in the Phase Field from Dynamic Adaptive and Fully Unstructured Gridding

  SPE Journal · 2025-09-25

  articleSenior author

  Summary Hydraulic fracturing remains a dynamic and evolving research field, with laboratory investigations continually revealing phenomena that challenge conventional modeling tools. Despite advances in simulation techniques, key limitations persist—particularly in representing fracture branching and the influence of distinct fracturing fluids. These complexities are well-suited to phase-field approaches, which replace sharp crack discontinuities with diffusive damage zones, enabling the modeling of intricate crack geometries. By incorporating surface energy—known to vary in the presence of different fluids—phase-field models also capture fluid-specific effects. Although the method introduces additional mathematical constructs, its foundations remain deeply rooted in Griffith’s classical energetic framework for crack propagation. Resolving narrow diffusive zones demands fine mesh resolution, resulting in significant computational overhead. The present work introduces a computational framework that accelerates phase-field simulations via dynamic adaptive gridding (DAG), concentrating refinement in regions of active fracture propagation. A low-pressure condition is imposed on newly formed cracks to reproduce pressure responses consistent with experimental studies. DAG is implemented on fully unstructured triangular grids, recursively refining elements while preserving child-triangle geometry. Hanging nodes generated during refinement are systematically removed to ensure compatibility with the numerical method. Newly formed cracks are identified via the phase-field variable, and affected cells are assigned low-pressure values in accordance with experimental observations. The mixed hybrid finite element method (MHFEM) is used to solve for pressure, guaranteeing local mass conservation. Phase-field evolution is also addressed with MHFEM, while mechanical deformation is solved using conventional finite element method (FEM). Fluid properties are characterized using equations sourced from National Institute of Standards and Technology databases, and the coupled system of three equations is solved using a sequentially iterative scheme. Speedups are computed across two laboratory-scale domains and one intermediate-scale example, providing insight into future field-scale developments. The DAG approach shows pronounced benefits at larger scales, yielding orders-of-magnitude improvements in computational efficiency. The characteristic pressure history—buildup, rapid decay, and slow propagation—is recovered with the imposed low-pressure condition. Few implementations of DAG exist for phase-field hydraulic fracturing models, and prior efforts are generally restricted to structured meshes and open-source libraries. This work also avoids the negative pressures at the fracture tip reported in other approaches.

  PublisherDOI

• Novel Copolymer Thickener for Live Oil CO2-EOR in Secondary and Tertiary Processes

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

  articleSenior author

  Abstract We investigate the effectiveness of a novel copolymer (copolymer of 1-octene and 1-dodecene with 32 repeating units, C8/C12-32) as a CO2 thickener for enhanced oil recovery (CO2-EOR) at a concentration of 0.3 wt %. The central objective is to evaluate the effectiveness of increased CO2 viscosity and mobility control at low concentration in a live oil. Previous work has focused on a dead oil, demonstrating the C8/C12-32 performance. In this work, we conduct experiments with a live oil. Experiments are conducted using a carbonate core with a 1.5-inch diameter and 10-inch length. CO2 is viscosified by adding 0.3 wt % of the C8/C12-32 at 3500 psi at 120 °C. The viscosity of CO2 is increased by about 2.5 times at 35 °C and 2.1 times at 120 °C. The viscosified CO2 is injected into the live-oil-saturated core in secondary injection, and neat CO2/and brine injection for comparison. In the tertiary process, viscosified CO2 is injected following neat CO2/brine. Under the same conditions, experiments are also conducted using 1.5 wt % C10-20 (an oligomer of 1-decene with 20 repeating units). In the past, we have used the C8/C12-32 oligomer in horizontal dead oil displacement at 3500 psi and 120 °C and 0.3 wt % concentration. In this work, we conduct similar experiments in a live oil. The bubble point pressure is around 2800 psi at 120 °C, and the GOR is about 635 scf/stb. Neat CO2 gives a recovery of about 63 % OOIP. The recovery from the viscosified CO2 injection is about 80 % OOIP. There is about a 27 % additional recovery from viscosified CO2. In the tertiary process, viscosified CO2 is injected following neat CO2 injection (63 % OOIP) and brine injection (57 % OOIP). Injection of viscosified CO2 after neat CO2 increases the recovery to about 72 % OOIP (additional recovery of about 14 %). Injection of viscosified CO2 after brine injection increases the recovery to about 68 % OOIP (additional recovery of about 19 %). Besides 0.3 wt % C8/C12-32 injection, we also conduct experiments using 1.5 wt % oligomer of 1-decne with 20 repeat units. The additional recovery from the viscosified CO2 injection by C10-20 yields about 17 % (secondary) and 18 % (tertiary), which is a substantially lower (secondary, 2-inch), demonstrating the effectiveness of the new thickener. The effectiveness of thickened CO2 is a major step in delaying the breakthrough and adding sustainability by keeping the injected CO2 in the subsurface.

  PublisherDOI

• Phase Equilibria of CO₂–Water and CO₂–Brine at High Temperatures: From Monte Carlo Simulations to the Equation of State

  Industrial & Engineering Chemistry Research · 2025-04-11 · 6 citations

  articleOpen accessSenior authorCorresponding

  Accurate modeling of density and CO2 partitioning in the CO2-water and CO2-brine systems over a wide pressure and temperature range is of high interest in many subsurface processes. We parametrize a new set of CPA and eCPA equations of state accounting for the CO2–H2O cross-association. The CO2-water phase diagrams and the CO2 solubility in NaCl brine are reproduced up to 700 K and 6 m of salinity. The density of CO2 in aqueous mixtures is predicted accurately, including the effect of CO2 dissolution, which may increase or decrease the density depending on conditions. From Monte Carlo simulations, the SPCE-EPM2 force field with optimized unlike parameters reproduces the high-temperature phase diagram without polarization corrections. In this work, our knowledge of the thermodynamics of CO2 in aqueous mixtures is expanded by providing a model for geothermal and CO2 sequestration conditions.

  PublisherDOI

• Thickened CO2-Enhanced Oil Recovery in Secondary and Tertiary Oil Recovery Flooding

  SPE Journal · 2025-09-29 · 3 citations

  articleSenior author

  Summary For this work, we investigated oil recovery performance in horizontal displacement by thickened carbon dioxide (CO2) using poly-1-decene with 20 repeat units (P1D-20) at 1.5 wt% concentration. Depending on temperature and (to a much lesser degree) pressure, the viscosity increase of CO2 was about four to five times. We performed both secondary and tertiary displacements in carbonate rocks at high temperatures of 110°C and 120°C. Most chemical additives become less effective at high temperatures. Two crude oils were used to saturate the cores. In secondary mode, the injection of thickened CO2 gave 35% and 40% higher oil recovery than neat injection in the two crude oils. Two types of tertiary processes were conducted on one of the two oil samples. After water injection, thickened CO2 injection gave 40% additional recovery. In another type of tertiary process, after neat CO2 injection, thickened CO2 was injected. There was a 35% additional recovery. We used a very high-salinity brine to establish initial water saturation. The displacements were carried out at 3,500 psi. Experimental findings highlight the effectiveness of thickened CO2 in mobility control by delaying breakthrough (BT) and enhancing sweep efficiency. In this study, we also explored the application of a slug of 0.3 pore volumes (PV) of thickened CO2 followed by neat CO2. The recovery performance was close to continuous injection of thickened CO2. In all our displacement experiments, neat and thickened CO2 injections were limited to around 1 PV. Efforts toward lower concentration viscosifier chemicals were also explored.

  PublisherDOI

• Benchmarking CO$_2$ Storage Simulations: Results from the 11th Society of Petroleum Engineers Comparative Solution Project

  ArXiv.org · 2025-07-05

  preprintOpen access

  The 11th Society of Petroleum Engineers Comparative Solution Project (shortened SPE11 herein) benchmarked simulation tools for geological carbon dioxide (CO$_2$) storage. A total of 45 groups from leading research institutions and industry across the globe signed up to participate, with 18 ultimately contributing valid results that were included in the comparative study reported here. This paper summarizes the SPE11. A comprehensive introduction and qualitative discussion of the submitted data are provided, together with an overview of online resources for accessing the full depth of data. A global metric for analyzing the relative distance between submissions is proposed and used to conduct a quantitative analysis of the submissions. This analysis attempts to statistically resolve the key aspects influencing the variability between submissions. The study shows that the major qualitative variation between the submitted results is related to thermal effects, dissolution-driven convective mixing, and resolution of facies discontinuities. Moreover, a strong dependence on grid resolution is observed across all three versions of the SPE11. However, our quantitative analysis suggests that the observed variations are predominantly influenced by factors not documented in the technical responses provided by the participants. We therefore identify that unreported variations due to human choices within the process of setting up, conducting, and reporting on the simulations underlying each SPE11 submission are at least as impactful as the computational choices reported.

  PublisherOA PDFDOI

• CO₂ Viscosification by Poly-α-olefins: Effect of Pressure, Temperature, Concentration, and Monomer Chain Length

  Energy & Fuels · 2025-08-18 · 4 citations

  articleSenior authorCorresponding

  Direct CO2 thickening with low-molecular-weight oligomers may significantly broaden the use of CO2 in the subsurface and increase the efficiency and safety of subsurface sequestration. This study investigates the thickening of supercritical carbon dioxide (scCO2) using poly-α-olefins (PAOs). The research focuses on the effects of pressure, temperature, concentration, and monomer chain length on the solubility and viscosification of PAOs in scCO2. Our findings reveal that PAOs, particularly poly-1-decene of 20 repeat units (P1D-20) and a copolymer of 1-dodecene-1-hexadecene (Cop12/16-12), significantly increase the viscosity of scCO2 at low concentrations. P1D-20 increases the viscosity of CO2 six times at 1.5 wt % at 35 °C and 24 MPa. Cop12/16-12 thickens 75% more than P1D-20 at 0.3 wt %. The thickening limitation is its solubility. PAO’s thickening efficiency is not drastically affected by temperature; relative viscosity remains practically constant at temperatures above 100 °C. Oligomers with different branch lengths in the same molecule look promising for effective viscosification.

  PublisherDOI

Frequent coauthors

• Hussein Hoteit

  King Abdullah University of Science and Technology

  32 shared

• Joachim Moortgat

  The Ohio State University

  27 shared

• Philip C. Myint

  Lawrence Livermore National Laboratory

  25 shared

• Tianhao Wu

  23 shared

• Ali Zidane

  Waste Management (United States)

  22 shared

• Hussein Mustapha

  19 shared

• Roussos Dimitrakopoulos

  McGill University

  19 shared

• Thomas Graf

  19 shared

Labs

• The Firoozabadi GroupPI

  We study very large-scale use of CO2 from different sources to prevent emission to the atmosphere.

Education

• PhD, Gas Engineering

  Illinois Institute of Technology

  1975

• MS, Gas Engineering

  Illinois Institute of Technology

  1972

Awards & honors

• Anthony Lucas Gold Medal