Increasing global need for energy security has spurred a need for enhanced oil and gas recovery from unconventional reservoirs. From a carbon cycle point of view however, enhanced hydrocarbon extraction results in higher concentrations of CO 2 in the atmosphere, which is detrimental to the environment. Coupling the potential of storing CO 2 with gas and oil recovery is one approach to limit the rise in atmospheric CO 2 concentrations while allowing for subsurface hydrocarbon recovery. Over the past few years, shale gas and oil have emerged as one of the leading contributors to overall subsurface hydrocarbon recovery. In this study, we explore the potential of combining the adsorption of CO 2 with the enhanced recovery of CH 4 , and compare the results with water which is conventionally used for hydraulic fracturing. The adsorption-desorption behaviour is accounted for using published experimental Langmuir isotherm data. The model assumes a simplified fracture shape where the flow is one-dimensional and Darcy's law is obeyed. Key performance indicators include tonnes of CO 2 injected per scm CH 4 recovered, tonnes of H 2 O injected per scm CH 4 recovered and tonnes of CO 2 sequestered per tonne of CO 2 injected

Brown, S.

Dowell, N.M.

Gadikota, G.

White Rose Research Online

1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).Peer-review under responsibility of the organizing committee of GHGT-13.doi: 10.1016/j.egypro.2017.03.1836  Energy Procedia  114 ( 2017 )  6942 – 6949 ScienceDirect13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland Modelling the adsorption-desorption behavior of CO2 in shales for permanent storage of CO2 and enhanced hydrocarbon extraction Solomon Browna*, Greeshma Gadikotab and Niall Mac Dowellc aDepartment of Chemical and Biological Engineering, The University of Sheffield, UK b Department of Civil and Environmental Engineering, Princeton University, New Jersey, USA cCentre for Process Systems Engineering, Imperial College London, UK Abstract Increasing global need for energy security has spurred a need for enhanced oil and gas recovery from unconventional reservoirs. From a carbon cycle point of view however, enhanced hydrocarbon extraction results in higher concentrations of CO2 in the atmosphere, which is detrimental to the environment. Coupling the potential of storing CO2 with gas and oil recovery is one approach to limit the rise in atmospheric CO2 concentrations while allowing for subsurface hydrocarbon recovery. Over the past few years, shale gas and oil have emerged as one of the leading contributors to overall subsurface hydrocarbon recovery. In this study, we explore the potential of combining the adsorption of CO2 with the enhanced recovery of CH4, and compare the results with water which is conventionally used for hydraulic fracturing. The adsorption-desorption behaviour is accounted for using published experimental Langmuir isotherm data. The model assumes a simplified fracture shape where the flow is one-dimensional and Darcy’s law is obeyed. Key performance indicators include tonnes of CO2 injected per scm CH4 recovered, tonnes of H2O injected per scm CH4 recovered and tonnes of CO2 sequestered per tonne of CO2 injected.  © 2017 The Authors. Published by Elsevier Ltd. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: Type your keywords here, separated by semicolons ;   Nomenclature ϕ Rock porosity (volume of voids per total volume)    * Corresponding author. Tel.: +44 1142227597 E-mail address: s.f.brown@sheffield.ac.uk Available online at www.sciencedirect.com© 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).Peer-review under responsibility of the organizing committee of GHGT-13. Solomon Brown et al. /  Energy Procedia  114 ( 2017 )  6942 – 6949 6943Sg gas saturation (volume of gas per volume of voids) ρb: bulk free gas density (mass of gas per volume of gas) ρa:  absorbed gas density (mass of absorbed gas per total volume of rock) κ: effective permeability (relative permeability multiplied by intrinsic permeability) µb  the bulk gas viscosity p pore gas pressure ωc  mass fraction of CO2   absorbed density of CO2   absorbed density of CH4 Dc CO2 dispersion coefficient u b Darcy flux of bulk gas phase n amount of gas absorbed (mol or mass) nmax max amount of gas that can be absorbed (mol or mass) K Langmuir Constant n1 amount of component 1 absorbed in binary system (mass or mol) ne excess amount absorbed  nabs absolute amount absorbed Va volume of pore space occupied by absorbed phase  excess absorbed mass of component 1 per unit volume of rock ρb Bulk gas density ρa absorbed phase density  absorbed mass fraction component 1  component 1 absolute absorption d distance between adjacent hydraulic fractures nf number of hydraulic fractures af surface area of each hydraulic fracture plane 1. Introduction Natural gas contained within shale formations represent a significant energy reserve, which has only begun to be exploited at very large scale in the last decade. This delay is due in large part to the extremely low permeability of these geological structures, which prohibits conventional hydrocarbon extraction methods. In order to increase the permeability, and thereby increase production to economic levels, the formation is ‘stimulated’ by hydraulic fracturing of the rock. Currently, given its low cost and availability, water is used as the main constituent of the fracturing fluid in over 95 % of operations [4], typically mixed with proppant, surfactants and biocide.   In recent years however, due to the issues related to the use of water, not least the amounts volumes required, attention has turned to finding alternative fracturing fluids. CO2 is one such substitute [9], which has long been used in hydrocarbon production through Enhanced Oil Recovery [5]. This is because of CO2s greater miscibility with hydrocarbons and enhanced desorption of CH4 from the clays that make up the shale formations that may lead to greater gas production.  Furthermore, given the current need to reduce the amount of CO2 release to the atmosphere and limit climate change, the possibility for storage of the injected CO2 in shale wells while also potentially enhancing hydrocarbon production is of interest. Work on predicting the impact of the use of CO2 on production has been presented in the literature, the models applied are complex fluid dynamic simulations [3] or assessments based on isotherms and empirical correlations [12]; the former of these methods requires significant computational power and is therefore not suited to a process level assessment, while the latter cannot be readily extended to account for more complex scenarios. The analysis of shale production performed by Patzek et al. [10,11] has shown that a simplified one-dimensional model can be used to characterise the flow within a shale reservoir; such a model provides a firm basis on which to base a process assessment of the injection and production of a shale well. Indeed, the model suggested by Patzek et al. [10,11] has been used by Edwards et al. [2] to predict the injectivity and capacity of depleted shale gas wells in the US. 6944   Solomon Brown et al. /  Energy Procedia  114 ( 2017 )  6942 – 6949 In this work we develop a rigorous process level model to assess both the increased potential for production of natural gas from shale formations when CO2 is used a fracturing fluid as compared to water and the degree of sequestration of the CO2. The paper proceeds as follows: Section 2 presents the flow model along with the boundary conditions applied for the fracturing scenarios as well as the adsorption, transport and thermophysical models. Section 3 presents the application of this model to the hydraulic fracturing of two differing formations, in each case the effect on production and degree of carbon sequestration is investigated. Finally, conclusions are drawn in Section 4. 2. Methodology 2.1. Fluid flow model In order to model the flow of CO2 and natural gas within the porous rock structure of the Shale reservoir we follow  and describe the fluid behaviour as a single-phase, isothermal, one-dimensional Darcy diffusional flow [1,11]. Figure 1 presents the assumed geometry of the shale gas reservoir, a horizontal well with perforations at regular intervals. It is further assumed that the permeability in the fracture and in the well is effectively infinite.   Fig. 1. Schematic representation of the assumed reservoir geometry The conservation of mass of the fluid mixture along with the assumption of Darcy flow can be written as the following non-linear diffusion equation, and given that the flow is isothermal this is a function of only the pressure: bb ab 0gp pS p pt x xp (1) In order to apply the above equation to a mixture of CO2 and natural gas within the bulk, Equation 1 is written in terms of the individual components, as follows: bb a ab, ,  ,  ,  0, cg c c c m ccp pS p p pt x xp (2) Further, an additional transport equation is solved to account for the flow of CO2 within the bulk fluid:  b a b bgb,  ,  ρ ,  , 0c c c c c ccg c cS p p p ut xS p Dx x (3) In Equation 3, the Darcy flux of the bulk gas phase is defined as follows:  Solomon Brown et al. /  Energy Procedia  114 ( 2017 )  6942 – 6949 6945bb , cpuxp (4) The model is then closed using the additional relation: m 1c  (5) 2.2. Adsorption-desorption The sorption behavior of CH4 and CO2 in porous media has been well described by the Langmuir adsorption model [6]. The Langmuir function describes the absolute amount of gas adsorbed to the media, for a two component mixture where the components are competing for the adsorption sites. The Langmuir model used to compute the adsorption for each component is given by:   max1 1 2 21i ii iK pn nK p K p (6) Following [1][6] to account for the free gas within the porous structure that is not adsorbed to the surface we define the excess adsorption by: abs b1 a n n V  (7) The above Langmuir isotherm can be used to estimate the excess adsorption, assuming that the parameters describe the absolute adsorption, as follows: The adsorbed mass fraction of component i  can then be defined as: Furthermore, for the purposes of the simulations carried out in this work the volume adjusted Peng-Robinson [8,13] is applied to predict the thermodynamic properties of the mixture for the CH4, CO2 and H2O, while the mixture viscosity is obtained using the Refprop database [8].  2.3. Initial and Boundary conditions In this work, we assume that the reservoir is initially equilibrated with a given reservoir pressure containing natural gas, represented by CH4 with a trace (0.1 wt%) amount of CO2.  The domain of each simulation is taken as the half-length between each fracture (see Fig. 1), in order to close the above flow model we develop appropriate initial and boundary conditions. For the boundary midway between fractures, a Neumann condition is applied for both equations 2 and 3. At the fracture face of the other boundary, we describe the initial injection of CO2 to create the fracture followed by the production of gas using a time dependent boundary condition for the two phases in the following section:  b b1 1 1e max 1 11 1 a1 1 2 2 1 1 a( , 11  , pK pK p K p p (8) abs1aabs abs1 1 2 1,  , 1,2,  , iipip p (9) 6946   Solomon Brown et al. /  Energy Procedia  114 ( 2017 )  6942 – 6949 2.3.1. Injection phase It is assumed that the pressure at the fracture phase is gradually increased to a level of 10 MPa ( injectionP  ) above the reservoir pressure, which for the sake of this work represents a reasonable level  at which a fracture may be opened [7]. In this work this period, is represented by  is 3 days, which is small relative to the time-scales of the dynamics involved. Further assuming that this increase in pressure is linear, for injectiont t  the boundary pressure is given by: Given that during this period the CO2 is being injected the condition for equation 3 is simply: , 1c boundary  (11) 2.3.2. Production phase  During the production phase of operation, i.e. injectiont t , it is assumed that the pressure drops below the reservoir pressure to a production pressure, here assumed to be 3.5 MPaboundaryP , while a Neumann condition is applied to equation 3:  , 0c boundaryx (12) 3. Results and Discussion The following presents the application of the model described above to simulate the impact of the use of CO2 as a fracturing fluid for hydraulic fracturing. For this purpose we use the formation parameters of the Marcellus Average and Barnett average formations obtained by Edwards et al. [1,2] by history matching against data for those formations. Table 1 presents the adsorption parameters, reservoir properties and assumed fracture geometry in each of these two cases. The simulations are performed for the domain between one axisymmetric fracture and midway point to the next, as shown in Figure 1. The wells are made up of a number of such fractures and the results are scaled accordingly. Figures 1 (a) and (b) represent the variation of the production rate and the cumulative mass of CH4 with time in the case of Marcellus Average Scenario, both where CO2 and water are used, respectively. Similar results are presented in Figures 2 (a) and (b) for the Barnett Average scenario.  As may be observed in Figure 1 while the production rate using the water is initially slightly higher (see Figure 1(a)) throughout the remainder of the simulation, the flowrate is slightly higher where CO2 is used. This results in an increased production of CH4 over the lifetime of the simulation of approximately 10%. The same trends are observed in the case of the Barnett Average scenario, though the flowrates are slightly lower due to the properties of the respective formation.   boundary reservoir injectioninjectiontP P Pt (10)  Solomon Brown et al. /  Energy Procedia  114 ( 2017 )  6942 – 6949 6947Table 1. Shale formation and fluid properties [1]  Marcellus Average Barnett Average Adsorption properties CH4 Langmuir K (MPa) 0.17 0.17 CO2 Langmuir K (MPa) 0.1 0.1 Max. CH4 Adsorption (kg m-3)  6.5 5 Max.CO2 Adsorption (kg m-3)  5 45 Adsorbed Phase density 1000 1000 Reservoir Properties Effective Permeability (nD)  25 45 Gas Saturation % 75 75 Porosity % 6 6 Reservoir Pressure (MPa) 25 35 Fracture properties  Fracture Height, V (m) 32 32 Fracture Width, H (m) 200 200 Half spacing between fractures (m) 15 15  (a)  (b)  Fig. 1 Variation of the (a) production rate (b) cumulative mass of CH4 produced with time from a single fracture using CO2 and Water as the fracturing fluid respectively for the Marcellus scenario. 02004000 1 2 3 4 5CH4Mass Flowrate (Mscf day -1)Time (yr)CO₂Water051015202530350 1 2 3 4 5Cumulative CH4produced (MMScf )Time (yr)CO₂Water6948   Solomon Brown et al. /  Energy Procedia  114 ( 2017 )  6942 – 6949 (a)  (b)  Fig. 2 Variation of the (a) production rate (b) cumulative mass of CH4 produced with time from a single fracture using CO2 and Water as the fracturing fluid respectively for the Barnett scenario. Table 2 presents the performance indicators used for these scenario, i.e. the amount of CH4 recovered per amount of fracturing fluid injected into the reservoir. As can be seen, for both the Marcellus and Barnett cases the amount of CH4 recovered is five times greater per tonne of CO2 than is the case of water. Table 2. Comparison of production over 5 years of simulation    Marcellus Average Barnett Average CH4 recovered (MMscf/tonne CO2) 2.79 1.38 CH4 recovered (MMscf/tonne Water) 2.48 1.06  4. Conclusion In this work, a process level modelling approach is used to describe the competitive adsorption and desorption behaviour of CO2 and CH4 for enhanced gas recovery. This model serves as a means to assess the effect of substituting CO2 as a fracturing fluid for the enhanced recovery of gas from geologic formations with pore spaces to the order of a few nanometers. For the purposes of this study, the model was applied to two different scenarios, each of which involved a different geological formation where the extraction of shale gas is of interest. The results from the simulations performed indicate, as expected, that natural gas production is higher with the use of CO2 than water, and that the amount of natural gas obtained per tonne of CO2 injected into the formation is higher. This conclusion coupled with the sequestration of the injected CO2 underlies the attractiveness of using CO2 for this purpose. Additional aspects, such as the relatively low viscosity of supercritical CO2 and thus lower pumping cost, provide further incentive for its use.  References [1] R.W.J. Edwards, M.A. Celia, K.W. Bandilla, F. Doster, C.M. Kanno, A Model To Estimate Carbon Dioxide Injectivity and Storage Capacity for Geological Sequestration in Shale Gas Wells, Environ. Sci. Technol. 49 (2015) 9222–9229. [2] R.W.J. Edwards, M.A. Celia, K.W. Bandilla, F. Doster, C.M. Kanno, A Model To Estimate Carbon Dioxide Injectivity and Storage Capacity for Geological Sequestration in Shale Gas Wells, Environ. Sci. Technol. 49 (2015) 9222–9229. [3] M.O. Eshkalak, E.W. Al-Shalabi, A. Sanaei, U. Aybar, K. Sepehrnoori, Simulation study on the CO2-driven enhanced gas recovery with sequestration versus the re-fracturing treatment of horizontal wells in the U.S. unconventional shale reservoirs, J. Nat. Gas Sci. 0501001502002503003504004500 1 2 3 4 5CH4Mass Flowrate (Mscf d -1)Time (yr)CO₂Water0510152025300 1 2 3 4 5Cumulative CH4produced (MMScf )Time (yr)CO₂Water Solomon Brown et al. /  Energy Procedia  114 ( 2017 )  6942 – 6949 6949Eng. 21 (2014) 1015–1024. [4] L. Gandossi, An overview of hydraulic fracturing and other formation stimulation technologies for shale gas production, 2013. [5] M.L. Godec, GLOBAL TECHNOLOGY ROADMAP FOR CCS IN INDUSTRY - Sectoral Assessment CO2 Enhanced Oil Recovery, 2011. [6] R. Heller, M. 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Natl. Acad. Sci. U. S. A. 110 (2013) 19731–6. [12] P. Pei, K. Ling, J. He, Z. Liu, Shale gas reservoir treatment by a CO2-based technology, J. Nat. Gas Sci. Eng. 26 (2015) 1595–1606. [13] A. Péneloux, E. Rauzy, R. Fréze, A consistent correction for Redlich-Kwong-Soave volumes, Fluid Phase Equilib. 8 (1982) 7–23.  

Modelling the adsorption-desorption behavior of CO2 in shales for

permanent storage of CO2 and enhanced hydrocarbon extraction

Solomon Brown

Greeshma Gadikota

Niall Mac Dowell

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Energy Procedia

Modelling the Adsorption-desorption Behavior of CO2 in Shales for Permanent Storage of CO2 and Enhanced Hydrocarbon Extraction

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Modelling the adsorption-desorption behavior of CO2 in shales for permanent storage of CO2 and enhanced hydrocarbon extraction

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