See discussions, stats, and author profiles for this publication at: https://www.researchgate.net/publication/305348701 Salt Precipitation During CO2 Injection and Changes in Reservoir Porosity and Permeability Presentation · June 2016 DOI: 10.13140/RG.2.1.1984.4083 CITATIONS READS 0 361 5 authors, including: Shuo Zhang Marinus van Dijke Tsinghua University Heriot-Watt University 30 PUBLICATIONS 284 CITATIONS 122 PUBLICATIONS 2,005 CITATIONS SEE PROFILE Sebastian Geiger Heriot-Watt University 217 PUBLICATIONS 3,538 CITATIONS SEE PROFILE Some of the authors of this publication are also working on these related projects: Pore scale reactive transport modelling View project Prediction of Imbibition Relative Permeability View project All content following this page was uploaded by Shuo Zhang on 16 July 2016. The user has requested enhancement of the downloaded file. SEE PROFILE Porosity-Permeability Relationships in Modeling Salt Precipitation During CO2 Sequestration Shuo Zhanga , Hui-Hai Liua , Marinus I.J. van Dijkeb , Sebastian Geigerb , Susan Agara a Aramco Research Center - Houston b Heriot-Watt University Overview Introduction Porosity-Permeability Relationships Theory Development Numerical Implementation, Case Study Discussions Overview Introduction Porosity-Permeability Relationships Theory Development Numerical Implementation, Case Study Discussions Salt Precipitation in CO2 Sequestration I I I I I I Water evaporates into dry gas Salt precipitation affects CO2 injectivity Observed in natural gas producing and storage wells Kleinitz et al. (2003),Place Jr et al. (1984) Extra pressure build-up in CO2 projects Baumann et al. (2014), Grude et al. (2014) Numerical studies Pruess and Müller (2009) Experimental studies Ott et al. (2012) Ott et al. (2015) Source: Eric Mackay Will The Reservoir Be Clogged? Numerical Studies Giorgis et al. (2007) I I Two-phase Darcy flow K0 , Kw (Sw ), Kg (Sw ) Capillary pressure Pc(Sw ) I Salt precipitation „ I Permeability change K („) Experiments Peysson et al. (2014) Andre et al. (2014) Wang et al. (2010) Overview Introduction Porosity-Permeability Relationships Theory Development Numerical Implementation, Case Study Discussions Porosity-Permeability Relationships in Literature Publication Pruess and Müller (2009) Andre et al. (2014) Giorgis et al. (2007) Zeidouni et al. (2009) Wang et al. (2010) Porosity-permeability relation k „/„0 ≠ „r 2 =( ) , „r = 0.9 k0 1 ≠ „r k „/„0 ≠ „r 2 =( ) , „r = 0.91 k0 1 ≠ „r k „/„0 ≠ „r · =( ) , „r = 0.3, · = 4.1 k0 1 ≠ „r k „ 1 ≠ „0 2 = ( )3 ( ) , „0 = 0.12 k0 „0 1≠„ k „ 1 ≠ „0 2 = ( )c ( ) , c = 2.4 k0 „0 1≠„ Relation type Verma and Pruess Verma and Pruess Verma and Pruess Carman-Kozeny Carman-Kozeny Carman-Kozeny Relation - Assumes Uniform Pore Size I Define porosity I Define permeability Ô „ = nt fir 2 · k= I fint r 4 Ô 8 · Porosity-permeability relationship „r 2 8· I After some algebra manipulation k= k=C „3 (1 ≠ „)2 I New permeability for new porosity k (1 ≠ „i )2 „ 3 = ( ) ki (1 ≠ „)2 „i Overview Introduction Porosity-Permeability Relationships Theory Development Numerical Implementation, Case Study Discussions van Genuchten/Mualem’s Relative Permeability Model Capillary Pressure (Pa) 106 van Genuchten PNM 105 S=[1+(– h)n ]-m ∆ 104 103 0.2 0.3 0.4 0.5 0.6 0.7 Saturation r = 1/h, Dv (r ) = 0.8 dS dr 0.9 1 sr rdr 2 ) 0 rdr krw (S) = S 1/2 [1 ≠ (1 ≠ S 1/m )m ]2 krw =S 1/2 0 (s Œ Change of Pore Size Distribution I I I I I The ratio of pore volume after salt precipitation to that before precipitation Sw ≠ Ss —= Sw The ratio of hydraulic radius ” = — ‰ , ‰ = 4.5 The ratio ofs permeability s rp Œ ”—rf (r )dr + rp rf (r )dr K 0 sŒ = · 1/2 [ ]2 K0 rf (r )dr 0 Van Genuchten relation sr rf (r )dr 0 f (S) = s Œ = 1 ≠ (1 ≠ S 1/m )m rf (r )dr 0 The ratio of permeability K = · 1/2 [(”— ≠ 1)(1 ≠ (1 ≠ S 1/m )m ) + 1]2 K0 New Constitutive Relations Between Mineral Reactions and Multi-Phase Flow Properties I h(S) = I kw kw 0 I kg kg0 I I I h0 (S) ” h0 (S) S Æ Sp S > Sp Y 3 2 S Æ Sp ]” — S ≠ Sp + ” 2 Sp 1/2 f (S) + (”— ≠ 1)f (Sp ) 2 = ) [ ] S > Sp [( S f (S) Y ] (Sp ≠ S)” 2 + (1 ≠ Sp ) 1/2 1 ≠ ”—f (S) + (”— ≠ 1)f (Sp ) 2 ] [ ] = [ 1≠S 1 ≠ f (S) [ 1 Continuum scale, closed-form relations No new measurements needed S Æ Sp S > Sp Pore Network Modeling, Numerical Estimation of Pc, Kr Source: Sebastian Geiger, HWU Pore Network Model and Initial Capillary Pressure Curve Capillary Pressure (Pa) 106 9.77 mm3 of Berea Sandstone Blue: Water, Red: CO2 van Genuchten PNM 105 S=[1+(– h)n ]-m 104 103 0.2 0.3 0.4 0.5 0.6 0.7 Saturation 0.8 0.9 1 Compare with Pore Network Modeling Capillary Pressure (Pa) 106 Our Model PNM post precipitation PNM initial I 105 I 104 I 103 0.2 0.3 0.4 0.5 0.6 0.7 Saturation 0.8 0.9 1 Capillary pressure increases due to precipitation Only water occupied pores are modified (S=0.2-0.5) Discontinuity at S=0.5 well captured by close-form equation Change in Relative Permeability Relative permeability of water 10≠1 I 10 ≠3 I 10≠5 10≠7 I 10≠9 Our Model PNM post precipitation PNM initial 10≠11 0.2 0.3 0.4 0.5 0.6 0.7 Saturation 0.8 0.9 I 1 Decrease porosity from 0.24 to 0.22 New model predicts relative permeability satisfactorily No tunable parameters Changes in relative permeability - 2 orders of magnitude Change in Permeability 100 Permeability ratio I 10≠1 I 10 ≠2 10≠3 0.19 Our model PNM data Traditional approach 0.2 0.21 0.22 Porosity 0.23 I 0.24 Zhang, Liu, Geiger, van Dijke, Agar, submitted to TIPM Traditional approach predicts exponential decrease of permeability Only water occupied pores should be modified for multi-phase flow Permeability does not decrease to zero Overview Introduction Porosity-Permeability Relationships Theory Development Numerical Implementation, Case Study Discussions Salt Precipitation by CO2 Dry-Out Porosity-permeability relationship k „ ≠ „c n =( ) , „c = 0.9, n = 2 ki „i ≠ „c Pruess and Müller (2009) Injection pressure exceeds limit due to reduced permeability New Code Predicts Less Reduction in Permeability 1 Verma Pruess New Model Permeability Ratio 0.8 0.6 0.4 0.2 0 10≠1 100 101 102 103 Radial distance (m) 104 105 New Code Predicts Less Increase in Injection Pressure ·107 Verma Pruess New Model Pressure (Pa) 5 I 4 I 3 I 2 I 1 10≠1 100 101 102 103 Radial distance (m) Zhang and Liu, submitted to IJGGC 104 105 Permeability does not decrease to zero No big increase in injection pressure Do not require pre-flushing with fresh water Supported by field evidence in CO2 pilot projects Overview Introduction Porosity-Permeability Relationships Theory Development Numerical Implementation, Case Study Discussions Does Salt Precipitate in Aqueous Phase? I I I Ott et al. (2015) Initial CO2 and salt occupy complementary space Overlap less than 5% Does Salt Precipitate in Aqueous Phase? I I I I I Miri et al. (2015) Experiment on a chip Strong film flow Salt precipitates in gas phase Not common in porous media What is the Experimentally Measured Porosity-Permeability Relationship I I I Bacci et al. (2013) I Follow the Verma and Pruess (1988) model Average porosity and permeability change of the entire core Representative element volume: one slice of the core Valid only for homogeneous precipitation What is the Experimentally Measured Porosity-Permeability Relationship I I I I Ott et al. (2015) Low flow rate: capillary back flow Precipitation close to injection surface High flow rate: uniform precipitation What is the Experimentally Measured Porosity-Permeability Relationship I Wang et al. (2010) measurement, I Our model, I Verma and Pruess (1988) model, k = 0.50 v 0.57 k0 k = 0.55 k0 k = 0.0017 k0 Will Salt Clog the Reservoir? Andre et al. (2014) Conclusions I Salt precipitates in aqueous phase I CO2 pathways stay open I Capillary back flow may cause clogging I New porosity-permeability relations for numerical simulations I Interpret experimental data for the right REVs Acknowledgments Hui-Hai Liu Sebastian Geiger Rink van Dijke Susan Agar Thank you/Questions? References I Andre, L., Peysson, Y., Azaroual, M., 2014. Well injectivity during co 2 storage operations in deep saline aquifers–part 2: Numerical simulations of drying, salt deposit mechanisms and role of capillary forces. international journal of Greenhouse Gas Control 22, 301–312. Bacci, G., Durucan, S., Korre, A., 2013. Experimental and numerical study of the effects of halite scaling on injectivity and seal performance during co 2 injection in saline aquifers. Energy Procedia 37, 3275–3282. Baumann, G., Henninges, J., De Lucia, M., 2014. Monitoring of saturation changes and salt precipitation during co 2 injection using pulsed neutron-gamma logging at the ketzin pilot site. International Journal of Greenhouse Gas Control 28, 134–146. Giorgis, T., Carpita, M., Battistelli, A., 2007. 2d modeling of salt precipitation during the injection of dry co 2 in a depleted gas reservoir. Energy Conversion and Management 48 (6), 1816–1826. Grude, S., Landrø, M., Dvorkin, J., 2014. Pressure effects caused by co 2 injection in the tubåen fm., the snøhvit field. International Journal of Greenhouse Gas Control 27, 178–187. Kleinitz, W., Dietzsch, G., Köhler, M., 2003. Halite scale formation in gas-producing wells. Chemical Engineering Research and Design 81 (3), 352–358. Miri, R., van Noort, R., Aagaard, P., Hellevang, H., 2015. New insights on the physics of salt precipitation during injection of co 2 into saline aquifers. International Journal of Greenhouse Gas Control 43, 10–21. Ott, H., de Kloe, K., van Bakel, M., Vos, F., van Pelt, A., Legerstee, P., Bauer, A., Eide, K., van der Linden, A., Berg, S., Makurat, A., 2012. Core-flood experiment for transport of reactive fluids in rocks. Review of Scientific Instruments 83 (8). URL http://scitation.aip.org/content/aip/journal/rsi/83/8/10.1063/1.4746997 Ott, H., Roels, S., De Kloe, K., 2015. Salt precipitation due to supercritical gas injection: I. capillary-driven flow in unimodal sandstone. International Journal of Greenhouse Gas Control 43, 247–255. References II Peysson, Y., Andre, L., Azaroual, M., 2014. Well injectivity during co 2 storage operations in deep saline aquifers—part 1: Experimental investigation of drying effects, salt precipitation and capillary forces. international journal of Greenhouse Gas Control 22, 291–300. Place Jr, M., Smith, J., et al., 1984. An unusual case of salt plugging in a high-pressure sour gas well. In: SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers. Pruess, K., Müller, N., 2009. Formation dry-out from co2 injection into saline aquifers: 1. effects of solids precipitation and their mitigation. Water Resources Research 45 (3). Verma, A., Pruess, K., 1988. Thermohydrological conditions and silica redistribution near high-level nuclear wastes emplaced in saturated geological formations. Journal of Geophysical Research: Solid Earth (1978–2012) 93 (B2), 1159–1173. Wang, Y., Luce, T., Ishizawa, C., Shuck, M., Smith, K., Ott, H., Appel, M., 2010. Halite precipitation and permeability assessment during supercritical co2 core flood. In: International symposium of the society of core analysis, Halifax. pp. 4–7. Zeidouni, M., Pooladi-Darvish, M., Keith, D., 2009. Analytical solution to evaluate salt precipitation during co 2 injection in saline aquifers. International Journal of Greenhouse Gas Control 3 (5), 600–611. View publication stats