Gaseous CO 2 migration in the shallow subsurface: Laboratory, Numerical modelling, and Field investigation

Transcription

1 Gaseous CO 2 migration in the shallow subsurface: Laboratory, Numerical modelling, and Field investigation Rune Nørbæk Lassen Karsten Høgh Jensen Majken Looms Department of Geoscience, Natural Resources and Planning Torben Sonnenborg GEUS Jacob Gudbjerg

2 Activities and achievement Laboratory: 1. Gaseous CO 2 migration in a 1D column. 1. Gaseous CO 2 migration in a 2D tank. 2. Heterogeneity enhanced exsolution of dissolved CO 2 (external partner) Field: 3. Tracking gaseous CO 2 with cross-borehole. 4. Detecting dissolved CO 2 with 3D cross-borehole ERT (external partner). Numerical modelling with T2VOC: 1. Modelling 1D and 2D laboratory experiments. 5. Modelling field experiments. 5. Gas migration control mechanisms. Papers: 1. Effects of Geologic Heterogeneity on Migration of gaseous CO 2 using Laboratory and Modelling Investigations (submitted). 2. Heterogeneity-Enhanced Gas Phase Formation in Shallow Aquifers During Leakage of CO 2 -Dissolved Water from Geologic Sequestration Sites (submitted). 3. Monitoring CO 2 gas-phase injection in a shallow sand aquifer using cross-borehole Ground Penetrating Radar (draft). 4. Monitoring a pilot CO 2 injection experiment in a shallow aquifer using 3D cross-well electrical resistance tomography (draft). 5. Modelling of near surface CO 2 leakage in the saturated zone (in process).

3 Paper 1: Laboratory work and modelling Macro-scale heterogeneity versus pore-scale heterogeneity Confining layers Local equilibrium assumption Injection and lateral spreading of gaseous CO 2. The applicability of the numerical code for large-scale field experiments.

4 Set-up and experiments Final project meeting 2014

5 Heterogeneity and injection rate The test confirmed our ideas about larger scale heterogeneity controlling overall gaseous CO 2 migration in a porous media environment. However dissolution processes and very low flow rates are controlled at microscale. Both the simulations and the experiments displayed that higher injection rates generated larger lateral and vertical spreading of the gaseous phase during the injection. Modelled Measured

6 Confining layers Modelled Measured Pressure builds before a barrier is breached. Knowing the location of the capillary barriers is essential for numerical models to predict reliable results. Barrier layers make point measurements very difficult to use outside lab.

7 Local equilibrium and field scale. Modelled (g/l) Measured Due to the necessity of a coarser discretization than that of the gaseous flow channels, local equilibrium resulted in an overestimation of dissolved CO 2 and delay of the breakthrough curves for the gaseous phase.

8 Paper 2: Heterogeneity enhanced gas-exsolution. M. Plampin, Colorado School of Mines As the CO2-saturated water flowed across the interfaces between the various types of porous media, a separate gas phase formed and evolved within the pores of the media. The study focused on the evolution of macroscopic gas saturations.

9 The definition ΔPo = ΔPi + Δpe ΔPi = Psat Pinj ΔPe = Pe,above Pe,below Copenhagen 2014

10 Example: Under saturated Heterogeneity enhanced Over saturated

11 Enhedens navn Conclusion Heterogeneity enhances gas evolution within a predictable range of conditions. Transitions from high- to low-permeability significantly affect gas evolution. Transitions from low- to high-permeability do not usually affect gas evolution.

12 Paper 3: Field experiment tracking gaseous CO 2 Next step from controlled laboratory setup. Cross borehole to detect gaseous CO 2 below the groundwater table. Heterogeneity lateral flow. Gas flow and groundwater flow are independent. Base for multiphase modelling.

13 Field site: Location and Setup Gaseous CO 2 injection rate was 15.6 g/minute 29 hours of injection (leakage problems) Cross borehole measurements can be directly converted to water content.

14 Background Geology profile and grain size Porosity based on

15 ZOP Post injection Final project meeting 2014

16 MOG profiles Post gas injection Left to right: MOG42 4H, MOG45 4H, Left to right: MOG13 21H, MOG42 27H, MOG45 26H, Copenhagen 2014

17 16 15 Stagnation and dissolution The maximum amount of gaseous CO The CO 2 dissolves rapidly once the injection has stopped.

18 Conclusion The gas phase was primarily located in two horizons; the lower zone, at 8.5m depth, and the second zone, just below 6m depth. The exception is north and east of the injection, where 6m is the only barrier. Initial spreading of the gas is towards the North and East. Largest amount of gas accumulates 2m south of the injection (sat 0.44). Large quantities of gaseous CO 2 most likely migrate away from the survey area.

19 Enhedens navn Field ERT pilot experiment X. Yang, Lawrence Livermore National Laboratory Evaluating the effectiveness of the 3D ERT method for monitoring the two opposing effects from gasphase and dissolved CO 2 in a shallow aquifer. There were 96 electrodes in four ERT boreholes bipole-bipole electrode data points (including reciprocal) 1% of noisy data Skip4 dipole-dipole array data points (including reciprocal) 7% of noisy data Sted og dato

20 5 m Final project meeting 2014 Field site ERT m 1 5 m 1 2 ERT 2 N 2 45 injector m ERT 4 4 (0,0 ) Total 17 sample points ERT 3 Groundwater flow Copenhagen 2014

21 Increase in conductivity versus increase in gas saturation hours hours 2 49 hours hours 26hours 50hours hours 24 hours 50 hours

22 Enhedens navn Increase in conductivity vs increase in gas sat hours hours hours hours 26hours 50hours hours 26 hours 49 hours

23 Cross section comparison hours ERT data (24 hours of injection) and CO 2 gas content by ZOP data (26 hours of injection) along a cross section intersecting boreholes 2 and 4. Copenhagen 2014

24 ERT1 3D time elapse of increased conductivity ERT2 ERT1 ERT2 ERT1 ERT2 Enhedens navn ERT4 ERT3 ERT4 ERT3 ERT4 ERT3 3 hours 24 hours 50 hours Conductivity Changes (%) Figure 7. Three-dimensional time lapse changes of electrical conductivity due to CO 2 injection. This is the inverted results of Skip4 data sets. The color opacity threshold was set to 4%.

25 Enhedens navn Conclusions ERT appears to be an effective tool for detection of the edges of CO 2 plumes in a controlled release. ERT may not capture the entire picture of CO 2 distribution ERT detects leakage long after the gas has dissolved due to tailing effect (increased cond.) 3D high-resolution temporal monitoring

26 Enhedens navn Paper 5: Field modelling and sensitivity Matching measured gas saturation from field experiments by employing a radial grid, and using parameters from in-situ sediment samples. Three controlling mechanisms we are investigating further: Model discretization and especially in relation to entry pressure values. Pockets are not always are the ideal trapping mechanism. Inclined low permeability layers on gas phase migration.

27 Enhedens navn Conceptual model and parameters 6 m 7 m 8.5m 6 m 7 m 8.5m Soil Perm. [m2] 1.Very Fine sand 3.13E Fine sand 8.35E coarse 1.03Esand Gravel* 1.41E- 12 Entry pres. [m] Brooks and Corey λ Residu al saturat ion 6 m 7 m 8.5m Injection: 15.6 g/min Boundaries. Constant head

28 Enhedens navn Four likely scenarios Upper: Left low permeable gravel layer. Right high permeable gravel layer. Lower: Left pocket of high permeable gravel into sand. Right, wedge of sand into highly permeable gravel.

29 Enhedens navn Discretization Boundary layer: For the gas to move from the coarse sand into the fine sand the gas saturation in the coarse sand will have to be above 0.7, where the capillary pressure of the coarse sand equals the entry pressure of the fine sand. However: If Pe < Z entry pressure becomes insignificant. Gas will move upward, and movement will only be limited by difference in permeability.

30 Enhedens navn Pockets Buoyancy driven flow Injectio n rate Delta entry pressure height perm (XY) breakthro ugh overfl ow max Gs kg/s cm cm m2 <<<< <<<< < % 1.E E- 11 x E E- 11 X E E- 11 x x E E- 11 x x E E- 11 x E E- 11 x x E E- 11 x x E E- 11 x x E E- 11 x x E E- 11 x E E- 11 x 76.7

31 Enhedens navn Inclined two 2D- cross section Example: Test: Inclination vs. Perm. Inclination vs. injec. Rate Inject. rate vs. Perm. Entry pres. vs. Perm Perm. Values: from grain size and pump test Inclination: 1-3 degrees Inject. rate Buoyancy (low) Entry pressure from grain size

32 Enhedens navn Conclusion While it proved impossible to find a unique solution to a specific case, using modelling as a predictive tool for leakage pathways at a CCS site is extremely difficult, and have to be used with care for risk assessment. This is not the fault of the model but a problem of scaling the local geology. You can predict more with a model, than what you know about geology but you can not know if the predicted solution is accurate for a specific site. A very real issue: Permeability estimated from grainsize are times lower than those measured with a pumptest at the field site.