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Acid Gas

The Experts below are selected from a list of 309 Experts worldwide ranked by ideXlab platform

François Montel – 1st expert on this subject based on the ideXlab platform

  • Role of hydrodynamism in compositional heterogeneities in Acid Gas reservoir
    73rd EAGE Conference and Exhibition incorporating SPE EUROPEC 2011, 2011
    Co-Authors: Estelle Bonnaud, François Montel, Vincent Lagneau, Daniel Dessort, Pierre Chiquet, Cécile Pabian-goyheneche, Honggang Zhou

    Abstract:

    Acid Gases (H2S and CO2) compositional heterogeneities have been noticed in many sour Gas reservoirs. Their occurrence is an important factor of economic depreciation. Thus, the knowledge of the Acid Gases distribution is a critical parameter for the design of field development. The mechanisms to explain compositional heterogeneities of Acid Gas in a reservoir are various. The paper aims at exploring the role of an active aquifer in contact with an initial high H2S content reservoir. The major mechanisms may be controlled by: * Differential solubility of Gases which can change the relative amounts of each Gas near the contact; * Active aquifer solubilization and transport which can export dissolved Gases thus enhancing dissolution on the long-term; * Diffusional transport in the Gas phase which can transfer the compositional anomalies farther from the Gas-water contact. To test the influence of several parameters on the efficiency of the Acid Gases leaching, simulations on basic geometries have been performed with the diphasic transport and geochemical software Hytec. The simulation results show a major role of the occurrence of horizontal impermeable barriers yields to sharp heterogeneities, including a decrease in Acid Gas near the contact, while farther areas H2S concentration remain unaffected.

  • High-Pressure AcidGas Viscosity Correlation
    SPE Journal, 2010
    Co-Authors: Guillaume Galliero, Christian Boned, Antoine Baylaucq, François Montel

    Abstract:

    International audienceAcid Gases containing hydrogen sulfide (H2S) are often encountered in the petroleum industry. However, reliable experiments on their thermophysical properties in reservoir conditions, on viscosity in particular, are scarce. From a modeling point of view, H2S and carbon dioxide (CO2) are polar compounds and as such are often considered rather difficult to model accurately. In this work, we propose a correlation with a strong physical background based on a corresponding-states (CS) approach to predict the viscosity from the temperature and the density of a large variety of systems for all stable thermodynamic states (Gas, liquid, and supercritical). In particular, this correlation is applicable to predict the viscosity of sour/AcidGas mixtures, whatever the thermodynamic conditions. This approach is based on the Lennard-Jones (LJ) fluid model, which has been studied extensively thanks to molecular-dynamics (MD) simulations over a wide range of thermodynamic conditions. This fluid model can be extended to deal with polar molecules such as CO2 or H2S without a loss of accuracy. First, we demonstrate that the proposed physically based correlation is able to provide an excellent estimation of the viscosity [with average absolute deviations (AADs) below 5%] of pure compounds, including normal-alkanes, CO2, or even H2S, whatever the thermodynamic conditions (Gas, liquid, or supercritical). Then, using a one-fluid approximation and a set of combining rules, the correlation is applied to various fluid mixtures in a fully predictive way (i.e., without any additional fitted parameters). Using this scheme, the deviations between predictions and measurements are as low as those on pure fluids using temperature and density as inputs. The viscosity of natural- and AcidGas mixtures at reservoir conditions is shown to be very well predicted by the proposed scheme. In addition, it is shown that this correlation can also be applied to predict reasonably the viscosity of asymmetric high-pressure mixtures, even in the liquid phase. This physically based approach is easy to include in any simulation software as long as, apart from temperature and density, the only inputs–the molecular parameters of each species–can be estimated from the critical temperature and the critical volume when not known

  • High-Pressure AcidGas Viscosity Correlation
    Spe Journal, 2010
    Co-Authors: Guillaume Galliero, Christian Boned, Antoine Baylaucq, François Montel

    Abstract:

    Acid Gases containing hydrogen sulfide (H2S) are often encountered in the petroleum industry. However, reliable experiments on their thermophysical properties in reservoir conditions, on viscosity in particular, are scarce. From a modeling point of view, H2S and carbon dioxide (CO2) are polar compounds and as such are often considered rather difficult to model accurately. In this work, we propose a correlation with a strong physical background based on a corresponding-states (CS) approach to predict the viscosity from the temperature and the density of a large variety of systems for all stable thermodynamic states (Gas, liquid, and supercritical). In particular, this correlation is applicable to predict the viscosity of sour/AcidGas mixtures, whatever the thermodynamic conditions. This approach is based on the Lennard-Jones (LJ) fluid model, which has been studied extensively thanks to molecular-dynamics (MD) simulations over a wide range of thermodynamic conditions. This fluid model can be extended to deal with polar molecules such as CO2 or H2S without a loss of accuracy. First, we demonstrate that the proposed physically based correlation is able to provide an excellent estimation of the viscosity [with average absolute deviations (AADs) below 5%] of pure compounds, including normal-alkanes, CO2, or even H2S, whatever the thermodynamic conditions (Gas, liquid, or supercritical). Then, using a one-fluid approximation and a set of combining rules, the correlation is applied to various fluid mixtures in a fully predictive way (i.e., without any additional fitted parameters). Using this scheme, the deviations between predictions and measurements are as low as those on pure fluids using temperature and density as inputs. The viscosity of natural- and AcidGas mixtures at reservoir conditions is shown to be very well predicted by the proposed scheme. In addition, it is shown that this correlation can also be applied to predict reasonably the viscosity of asymmetric high-pressure mixtures, even in the liquid phase. This physically based approach is easy to include in any simulation software as long as, apart from temperature and density, the only inputs–the molecular parameters of each species–can be estimated from the critical temperature and the critical volume when not known.

Stefan Bachu – 2nd expert on this subject based on the ideXlab platform

  • review of failures for wells used for co2 and Acid Gas injection in alberta canada
    Energy Procedia, 2009
    Co-Authors: Stefan Bachu, Theresa L Watson

    Abstract:

    Abstract Wells have been identified as posing a greater risk for leakage from CO2 storage sites than geological features such as faults and fractures, particularly in mature sedimentary basins with high well density such as those onshore in North America. A commonly-held belief is that CO2 injection wells will pose a lesser risk than wells drilled for other purposes because greater care would be taken in regard to their completion and operation. The existence of CO2 and Acid Gas injection operations in Alberta, Canada, provided the opportunity to test this hypothesis. Currently in Alberta there are 31 wells used for CO2 injection and 48 wells used for the disposal of produced Acid Gas (a mixture of CO2 and H2S that is separated from sour Gas to meet pipeline and market specifications). Only 22 wells were drilled specifically with the purpose of injecting CO2 or Acid Gas; all others are previous wells that have been subsequently converted to injection wells. Well failures include: surface casing vent flow, casing failure, tubing failure, packer failure, and zonal isolation failure. The incidence of well failure is greater in the case of converted wells than in the case of wells drilled and completed for injection purposes. Most failures are not caused by injection; they are due to general causes encountered in the general well population. Failures due to injection are mostly tubing and packer failures, which are monitored by regulation and are easily detected and repaired. The incidence of well failure is greater for wells drilled prior to the advent of regulations in 1994 regarding drilling and completion of injection wells. While the incidence of failure in the CO2 and Acid Gas injection wells in Alberta is comparable to that in the general well population, the analysis indicates that injection wells drilled for purpose and under a proper regulatory regime have a lesser incidence of failure than the general well population. A proper regulatory framework for CO2 injection wells is essential for reducing and preventing well failures.

  • Deep Injection of Acid Gas in Western Canada
    Developments in water science, 2007
    Co-Authors: Stefan Bachu, K. Haug, Karsten Michael, B.e. Buschkuehle, J.j. Adams

    Abstract:

    Publisher Summary This chapter elaborates the understanding of the technology and characteristics of the AcidGas injection operations that will help in expanding its application for safe disposal of Acid and greenhouse Gases in Western Canada. AcidGas injection currently takes place in the Alberta basin in western Canada, with most of the operations being located in Alberta and several in Northeastern British Columbia. The AcidGas injection operations constitute a commercial-scale analogue for future large-scale CO 2 geological sequestration efforts to reduce CO 2 emissions into the atmosphere from large CO 2 point sources. The technology and engineering experience is developed at these AcidGas injection operations (i.e., design, materials, leakage prevention, and safety) can be easily adopted for large-scale CO 2 geological sequestration operations, because a CO 2 stream with no H 2 S is less corrosive and hazardous. However, as these operations are scaled-up, the leakage risk moves from the near well to the surrounding area, where the uncertainty in geology and reservoir or aquifer characteristics is greater.

  • overview of Acid Gas injection operations in western canada
    Greenhouse Gas Control Technologies 7#R##N#Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies 5– September 2004 Va, 2005
    Co-Authors: Stefan Bachu, William D Gunter

    Abstract:

    Publisher Summary This chapter illustrates that over 2.5 Mt CO 2 and 2.0 Mt H 2 S have been injected into deep saline aquifers and depleted hydrocarbon reservoirs at 48 sites in western Canada by the end of 2003, driven by the need to dispose of H 2 S produced with natural Gas from sour Gas reservoirs. Injection of Acid Gas (CO 2 and H 2 S) occurs over a wide range of aquifer and reservoir characteristics, Acid Gas compositions, and operating conditions. These AcidGas injection operations are a commercial scale analogue to CO 2 geological storage and are representative of aquifers and reservoirs in continental sedimentary basins that have undergone compaction and erosion, like those between the Rocky Mountains and the Appalachians in North America, where CO 2 injection and geological storage on a large scale is implemented in Canada and the United States.

Nguyen Van Duc Long – 3rd expert on this subject based on the ideXlab platform

  • novel Acid Gas removal process based on self heat recuperation technology
    International Journal of Greenhouse Gas Control, 2017
    Co-Authors: Nguyen Van Duc Long

    Abstract:

    Abstract Chemical absorption is the most common technology used in the Acid Gas removal unit (AGRU) for treating natural Gas. On the other hand, the regenerator requiring large amounts of energy needed for the latent heat of a phase change makes this an energy intensive process. In this study, several distillation columns with a modified heat circulation module based on self-heat recuperation technology were proposed to enhance the energy efficiency of the AGRU. This innovative self-heat recuperation technology circulates the latent and sensible heat in the thermal process. All simulations were conducted using ASPEN HYSYS V8.6, while KG-TOWER® software was employed to size all the columns. The results showed that the proposed modified configuration can save up 62.5% and 45.9% in terms of the reboiler duty and operating cost, respectively, compared to a conventional AGRU. This brought a saving of 38.0% in terms of the total annual cost. The results also indicated that the carbon emissions could be saved up to 45.4%. The proposed process can be employed to both close-boiling mixtures and wide-boiling mixtures. In addition, a sensitive analysis of the utility costs on the performance of the suggested AGRU configuration were investigated. The retrofit an existing Acid Gas removal process was performed to enhance both the energy efficiency and capacity.