Experiments were conducted in a semibatch stirred tank reactor, equipped with an in situ particle size analyzer, to study the rate of formation of hydrates from mixtures of carbon dioxide and methane. Two gas mixtures of CO 2 (1) + CH 4 (2), one with x 1 = 0.4 and the other with x 1 = 0.6, were used in the current study. The experimental temperature ranged from 274 to 276 K and the experimental pressure ranged from 20 to 27 bar absolute. The range of temperatures was bounded by the freezing point of water and the temperature at which the CO 2 vapor pressure curve intersects the methane hydrate curve. Initially, the results were analyzed using the kinetic model of Englezos et al. (Chem. Eng. Sci. 1987, 42, 2659−2666. After a careful reexamination of the model of Englezos et al., it was realized that the mathematical model for gas hydrate formation from gas mixtures could be simplified by directly incorporating the hydrate phase stoichiometry. The new approach has the added advantage that the intrinsic rate constant of gas hydrate formation is required for only a single component. Thus, a new approach was proposed to model the kinetics of gas hydrate formation from a mixture of gases, and the results from these predictions were compared to the results obtained using the model of Englezos et al. The root-mean squares of the relative errors between the experimental results and the predictions of the new model and the model of Englezos et al. were found to be 2.70% and 4.29%, respectively.
Naturally occurring gas hydrates are regarded as an important future source of energy and considerable efforts are currently being invested to develop methods for an economically viable recovery of this resource. The recovery of natural gas from gas hydrate deposits has been studied by a number of researchers. Depressurization of the reservoir is seen as a favorable method because of its relatively low energy requirements. While lowering the pressure in the production well seems to be a straight forward approach to destabilize methane hydrates, the intrinsic kinetics of CH 4 -hydrate decomposition and fluid flow lead to complex processes of mass and heat transfer within the deposit. In order to develop a better understanding of the processes and conditions governing the production of methane from methane hydrates it is necessary to study the sensitivity of gas production to the effects of factors such as pressure, temperature, thermal conductivity, permeability, porosity on methane recovery from naturally occurring gas hydrates. A simplified model is the base for an ensemble of reservoir simulations to study which parameters govern productivity and how these factors might interact. OPEN ACCESSEnergies 2014, 7 2149
Following a recent study by Giraldo et al. (Giraldo, C.; Maini, B.; Bishnoi, P. R. A simplified approach to modeling the rate of formation of gas hydrates formed from mixtures of gases. Energy Fuels 2013, 27, 1204−1211), in which a new stoichiometry-based approach was taken to model the rate of gas hydrate formation for mixed gases, a new stoichiometric approach has been proposed to describe the kinetics of gas hydrate decomposition from mixed gases. Similar to the model of gas hydrate formation by Giraldo et al., the newly proposed model of gas hydrate decomposition has the advantage that the intrinsic rate constant of gas hydrate decomposition is only required for a single component. To test the model, gas hydrate decomposition experiments were conducted in a semi-batch stirred-tank reactor, equipped with an in situ particle size analyzer, to study the rate of decomposition of gas hydrates formed from mixtures of carbon dioxide and methane. Two gas mixtures of CO 2 (1) + CH 4 (2), one with x 1 = 0.4 and the other with x 1 = 0.6, were used for the current study. The experimental temperatures ranged from 274 to 276 K, and the experimental pressures ranged from 16 to 22 bar. The new approach was used to model the kinetics of gas hydrate decomposition, and the results from these predictions were compared to the results obtained using the model by Clarke and Bishnoi (Clarke, M. A.; Bishnoi, P. R. Measuring and modelling the rate of decomposition of gas hydrates formed from mixtures of methane and ethane. Chem. Eng. Sci. 2001, 56, 4715−4724 and Clarke, M. A.; Bishnoi, P. R. Determination of the intrinsic rate constant and activation energy of CO 2 gas hydrate decomposition using in-situ particle size analysis. Chem. Eng. Sci. 2004, 59, 2983−2993. The root-mean-square of the relative errors between the predictions of the new model and the model by Clarke and Bishnoi are 4.15 and 6.21%, respectively. Further validation of the new model was performed using it to fit the data by Clarke and Bishnoi on the decomposition of both sI and sII gas hydrates formed from mixtures of CH 4 (1) + C 2 H 6 (2). When applied to these data sets, the root-mean-square of the relative errors between the predictions of the new model and the model by Clarke and Bishnoi are 2.58 and 1.60%, respectively.
Summary Acid-fracturing treatments are used commonly to enhance the productivity of carbonate formations with low-permeability zones. Various forms of hydrochloric acid (HCL) are used to create deep etched fractures. However, regular HCl reacts very fast with limestone and high-temperature dolomite formations and, unless retarded, will produce a fracture with low conductivity. In addition, concentrated HCl-based acids are very corrosive to well tubulars, especially at high temperatures. To address problems associated with concentrated acids, various retarded acids were introduced. Organic acids were used also in some cases. These organic acid systems were used successfully to acid fracture several wells in a deep gas reservoir in Saudi Arabia. Field data, however, indicated that there is a need to create deeper and more-conductive fractures. To achieve this goal, it was decided to conduct a field trial with a newly developed acid system. The new acid system is an ester of an organic acid in the form of solid beads. The ester reacts with water (hydrolyzes) at bottomhole temperature and produces lactic acid, which reacts with carbonate minerals and etches the surface of the fracture. The system was examined thoroughly in the laboratory and showed promising results. The treatment was conducted in the field without encountering operational problems. After successful placement of the solid beads in the fracture, the well was shut in for 24 hours to give ample time for the ester to hydrolyze and for the generated acid to react with the formation rock. The well was allowed to flow, and samples of the fluids produced were collected to understand chemical reactions that occurred during the treatment. The treatment has resulted in a slight increase in gas production, and no significant improvement was noted over a 9-month period. Consequently, the well was matrix acidized with 28 wt% HCl and responded positively to the treatment. This paper will discuss major reactions that occurred during these treatments and how they impacted well response. Lessons learned and recommendations to improve the results of this new acid system will be given.
Acidizing core flooding experiments in carbonates are typically performed in the laboratory in order to observe different physical phenomena and to design acid stimulation jobs in the field. The experiments are usually well defined in terms of mineralogy, permeability, porosity, pressure, temperature and salinity. During the tests, key parameters are analyzed such as the pore volume of acid needed to create wormholes and breakthrough as well as pressure and permeability time-evolution. In reality, the result of an acid stimulation in the field is difficult to predict because of the heterogeneous nature of carbonate formations, complexity of such reactive transport phenomenon, and more importantly the uncertainties related to subsurface well conditions. Stimulation models and numerical tools can help bridge the gap between the laboratory observations and real field applications. We utilize selected core flooding results obtained from the QP - TOTAL collaboration on acid stimulation and use these measurements as input for different acid stimulation software. Subsequently, a benchmarking of commercial and academic acid stimulation software at the well scale is performed. The main criteria for this comparison are the capacity of modeling improved acid stimulation under constant or varying pumping rates, the capability of modeling complex fluids such as chemical diverters and relative permeability modifiers and the ability to simulate different well configurations. Then, a sensitivity analysis on selected key parameters such as the dissolution model, pore volume to breakthrough and solute velocities is conducted. Finally, predictions from numerical models are compared to acid stimulation field results from literature, for Middle Eastern carbonate. We try to history match the results and we identify main areas of improvement for future development of acid stimulation software.
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