Analysis of Rates of Geochemical Reactions.- Transition State Theory and Molecular Orbital Calculations Applied to Rates and Reaction Mechanisms in Geochemical Kinetics.- The Mineral-Water Interface.- Kinetics of Sorption-Desorption.- Kinetics of Mineral Dissolution.- Data Fitting Techniques with Applications to Mineral Dissolution Kinetics.- Nucleation, Growth, and Aggregation of Mineral Phases: Mechanisms and Kinetic Controls.- Microbiological Controls on Geochemical Kinetics 1: Fundamentals and Case Study on Microbial Fe(III) Oxide Reduction.- Microbiological Controls on Geochemical Kinetics 2: Case Study on Microbial Oxidation of Metal Sulfide Minerals and Future Prospects.- Quantitative Approaches to Characterizing Natural Chemical Weathering Rates.- Geochemical Kinetics and Transport.- Isotope Geochemistry as a Tool for Deciphering Kinetics of Water-Rock Interaction.- Kinetics of Global Geochemical Cycles.

Kinetics of Water-Rock Interaction

Numerical study on heat extraction performance of a multilateral-well enhanced geothermal system considering complex hydraulic and natural fractures

Frac Hit Induced Production Losses: Evaluating Root Causes, Damage Location, Possible Prevention Methods and Success of Remedial Treatments

The effects of gas-fluid-rock interactions on CO 2 injection and storage: insights from reactive transport modeling Yitian Xiao a *, Tianfu Xu b , and Karsten Pruess b a b ExxonMobil Upstream Research Company, Houston TX 77027, USA Lawrence Berkeley National Laboratory, Berkeley, CA 94720, USA Abstract Possible means of reducing atmospheric CO 2 emissions include injecting CO 2 in petroleum reservoirs for Enhanced Oil Recovery or storing CO 2 in deep saline aquifers. Large-scale injection of CO 2 into subsurface reservoirs would induce a complex interplay of multiphase flow, capillary trapping, dissolution, diffusion, convection, and chemical reactions that may have significant impacts on both short-term injection performance and long-term fate of CO 2 storage. Reactive Transport Modeling is a promising approach that can be used to predict the spatial and temporal evolution of injected CO 2 and associated gas-fluid-rock interactions. This presentation will summarize recent advances in reactive transport modeling of CO 2 storage and review key technical issues on (1) the short- and long-term behavior of injected CO 2 in geological formations; (2) the role of reservoir mineral heterogeneity on injection performance and storage security; (3) the effect of gas mixtures (e.g., H 2 S and SO 2 ) on CO 2 storage; and (4) the physical and chemical processes during potential leakage of CO2 from the primary storage reservoir. Simulation results suggest that CO 2 trapping capacity, rate, and impact on reservoir rocks depend on primary mineral composition and injecting gas mixtures. For example, models predict that the injection of CO 2 alone or co-injection with H 2 S in both sandstone and carbonate reservoirs lead to acidified zones and mineral dissolution adjacent to the injection well, and carbonate precipitation and mineral trapping away from the well. Co-injection of CO 2 with H 2 S and in particular with SO 2 causes greater formation alteration and complex sulfur mineral (alunite, anhydrite, and pyrite) trapping, sometimes at a much faster rate than previously thought. The results from Reactive Transport Modeling provide valuable insights for analyzing and assessing the dynamic behaviors of injected CO2, identifying and characterizing potential storage sites, and managing injection performance and reducing costs. Keywords: CO2 injection and storage, gas-fluid-rock interactions, reactive transport modeling, ccs.

The effects of gas-fluid-rock interactions on CO2 injection and storage: Insights from reactive transport modeling

A Semianalytical Approach To Model Two-Phase Flowback of Shale-Gas Wells With Complex-Fracture-Network Geometries

Recovery Efficiency in Hydraulically Fractured Shale Gas Reservoirs

Development of a halite dissolution numerical model for hydraulically fractured shale formations (Part I)


 Conventional hydrocarbon reservoirs, from an engineering and economic standpoint, are the easiest and most cost-efficient deposits to develop and produce. However, as economic deposits of conventional oil/gas become scarce, hydrocarbon recovered from tight sands and shale deposits will likely fill the void created by diminished conventional oil and gas sources. The purpose of this paper is to review the numerical methods available for simulating multiphase flow in highly fractured reservoirs and present a concise method to implement a fully implicit, two-phase numerical model for simulating multiphase flow, and predicting fluid recovery in highly fractured tight gas and shale gas reservoirs. The paper covers the five primary numerical modeling categories. It addresses the physical and theoretical concepts that support the development of numerical reservoir models and sequentially presents the stages of model development starting with mass balance fundamentals, Darcy’s law and the continuity equations. The paper shows how to develop and reduce the fluid transport equations. It also addresses equation discretization and linearization, model validation and typical model outputs. More advanced topics such as compositional models, reactive transport models, and artificial neural network models are also briefly discussed. The paper concludes with a discussion of field-scale model implementation challenges and constraints. The paper focuses on concisely and clearly presenting fundamental methods available to the novice petroleum engineer with the goal of improving their understanding of the inner workings of commercially available black box reservoir simulators. The paper assumes the reader has a working understanding of flow a porous media, Darcy’s law, and reservoir rock and fluid properties such as porosity, permeability, saturation, formation volume factor, viscosity, and capillary pressure. The paper does not explain these physical concepts neither are the laboratory tests needed to quantify these physical phenomena addressed. However, the paper briefly addresses these concepts in the context of sampling, uncertainty, upscaling, field-scale distribution, and the impact they have on field-scale numerical models.

Maxian B. Seales

Papers

Recovery Efficiency in Hydraulically Fractured Shale Gas Reservoirs

Development of a halite dissolution numerical model for hydraulically fractured shale formations (Part I)

Multiphase Flow in Highly Fractured Shale Gas Reservoirs: Review of Fundamental Concepts for Numerical Simulation

A Numerical Study of Factors Affecting Fracture-Fluid Cleanup and Produced Gas/Water in Marcellus Shale: Part II

Numerical Analysis of the Source of Excessive Na + and Cl – Species in Flowback Water From Hydraulically Fractured Shale Formations