A Numerical Model of the Non-Isothermal Flow of Carbon Dioxide in Wellbores

Cronshaw, Mark B.; Bolling, J.D.

doi:10.2118/10735-ms

Cited by 24 publications

(28 citation statements)

References 7 publications

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“…The technology for transporting 17 , compressing and injecting 18,19 carbon dioxide is well-established, due to the widespread use of CO 2 in enhanced oil recovery, and is readily adapted for the purposes of underground storage. The 20 (as well as in depleted gas fields) and the disposal of acid gases by underground injection 21,22 are also relevant, especially the procedures that have been developed for assessing the suitability of storage sites.…”

Section: Introductionmentioning

confidence: 99%

Role of Convective Mixing in the Long-Term Storage of Carbon Dioxide in Deep Saline Formations

Ennis‐King

Paterson

2003

SPE Annual Technical Conference and Exhibition

139

126

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractStorage of carbon dioxide in deep formations is being actively considered for the reduction of greenhouse gas emissions. Relevant experience in the petroleum industry comes from natural gas storage and enhanced recovery using carbon dioxide, but this experience is over a time scale less than the hundreds or thousands of years required for carbon dioxide storage. On these long time scales different mechanisms need to be considered.In the long-term the dominant mechanism for dissolution of carbon dioxide in formation water is convective mixing rather than pure diffusion. This arises because the density of formation water increases upon dissolution of carbon dioxide, creating a density instability. Linear stability analysis has been used to estimate the time required for this instability to occur in anisotropic systems. For sufficiently thick formations with moderate vertical permeability, this time is years to decades. Further approximate analysis shows that the time needed for the injected gas to dissolve completely is typically much longer, of the order of hundreds to thousands of years, depending on the vertical permeability. This theoretical analysis is found to be in broad agreement with the results of fine scale reservoir simulations. Laboratory experiments on an analogous system demonstrate the same phenomena.

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Section: Introductionmentioning

confidence: 99%

Role of Convective Mixing in the Long-Term Storage of Carbon Dioxide in Deep Saline Formations

Ennis‐King

Paterson

2003

SPE Annual Technical Conference and Exhibition

139

126

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“…Consider that the formation fractured is infinite, homogeneous, and isotropic; ignore the effect of fluid and heat flow on geomechanical-parameter variations. For a horizontal fracture, the extension process is in accord with the Khristianovic-Geertsma-de Klerk (KGD) model (Geertsma and de Klerk 1969): Ignore temperature variations of the fluid along the vertical direction of the fracture, ignore the heat exchange of the formation vertically, and ignore the influence of the proppant. Fig.…”

Section: Temperature-field Modelsmentioning

confidence: 99%

Calculation of Temperature in Fracture for Carbon Dioxide Fracturing

Wang

Sun

2016

SPE Journal

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Carbon dioxide (CO 2 ) temperature-field models in the wellbore and fracture are proposed to calculate transitions of fluid-phase states and variations of the fluid thermal-physical parameters during CO 2 fracturing. The models take two items into account in the formula of the specific enthalpy: the internal energy and the flow work. The flow work is usually ignored for conventional hydraulic fracturing. When computing the CO 2 temperature at the bottom of the hole, we find a 3.8 C deviation (well depth of 2000 m, injection temperature: -20 C) if the effects of the flow-work variations on the fluid temperatures are ignored. The phase states of CO 2 vary from liquid to the supercritical state, and the position of the phase-state transition moves from inside the wellbore to the fracture. The fluid temperatures in the wellbore and fracture drop rapidly, whereas the pressures rise gradually. The temperature differences between the fracture fluid and the matrix-leakoff zone are small, and the cooling-formation distance increases with time and the injection rate.

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“…Examples of models used to solve the transient flow in acid gas and/or CO 2 injection wells have been described, among others, by Cronshaw and Bolling 1982;Wang and Carroll 2006;Pan et al (2009). Assuming that thermodynamic conditions and fluid velocity are constant across any pipe section, the one-dimensional momentum and energy conservation equations for steady-state single-phase flow are as follows (Hasan and Kabir 2002;Paterson et al 2008):…”

Section: Basic Equations For Pipe Flowmentioning

confidence: 99%

Injection of Acid Gas Mixtures in Sour Oil Reservoirs: Analysis of Near-Wellbore Processes with Coupled Modelling of Well and Reservoir Flow

2010

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The reinjection of sour or acid gas mixtures is often required for the exploitation of hydrocarbon reservoirs containing remarkable amounts of acid gases (H 2 S and CO 2 ) to reduce the environmental impact of field exploitation and provide pressure support for enhanced oil recovery (EOR) purposes. Sour and acid gas injection in geological structures can be modelled with TMGAS, a new Equation of State (EOS) module for the TOUGH2 reservoir simulator. TMGAS can simulate the two-phase behaviour of NaCl-dominated brines in equilibrium with a non-aqueous (NA) phase, made up of inorganic gases such as CO 2 and H 2 S and hydrocarbons (pure as well as pseudo-components), up to the high pressures (∼100 MPa) and temperatures (∼200 • C) found in deep sedimentary basins. This study is focused on the near-wellbore processes driven by the injection of an acid gas mixture in a hypothetical high-pressure, under-saturated sour oil reservoir at a well-sector scale and at conditions for which the injected gas is fully miscible with the oil. Relevant-coupled processes are simulated, including the displacement of oil originally in place, the evaporation of connate brine, the salt concentration and consequent halite precipitation, as well as non-isothermal effects generated by the injection of the acid gas mixture at temperatures lower than initial reservoir temperature. Non-isothermal effects are studied by modelling in a coupled way wellbore and reservoir flow with a modified version of the TOUGH2 reservoir simulator. The described approach is limited to single-phase wellbore flow conditions occurring when injecting sour, acid or greenhouse gas mixtures in high-pressure geological structures.

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A Numerical Model of the Non-Isothermal Flow of Carbon Dioxide in Wellbores

Cited by 24 publications

References 7 publications

Role of Convective Mixing in the Long-Term Storage of Carbon Dioxide in Deep Saline Formations

Role of Convective Mixing in the Long-Term Storage of Carbon Dioxide in Deep Saline Formations

Calculation of Temperature in Fracture for Carbon Dioxide Fracturing

Injection of Acid Gas Mixtures in Sour Oil Reservoirs: Analysis of Near-Wellbore Processes with Coupled Modelling of Well and Reservoir Flow

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