Characterization of Hysteretic Multiphase Flow from the MM to M Scale in Heterogeneous Rocks

Incorporating mm-m scale capillary pressure heterogeneity into upscaled numerical models is key to the successful prediction of low flow potential plume migration and trapping at the field scale. Under such conditions, the upscaled, equivalent relative permeability incorporating capillary pressure heterogeneity is far from that derived conventionally at the viscous limit, dependent on the heterogeneity structure and flow rate, i.e. dependent on the capillary number. Recent work at the SCA 2017 symposium (SCA2017-022) demonstrated how equivalent functions can be obtained on heterogeneous rock cores from the subsurface under drainage conditions; going beyond traditional SCAL. Experimental observations using medical CT scanning can be combined with numerical modelling so that heterogeneous subsurface rock cores can be directly characterized and used to populate field scale reservoir models. In this work, we extend this characterization approach by incorporating imbibition cycles into the methodology. We use a Bunter sandstone core with several experimental CO2 – Brine core flood datasets at different flow rates (2x drainage, 1x imbibition and 2x trapping) to demonstrate the characterization of hysteretic multiphase flow functions in water-wet rocks. We show that mm-m scale experimental saturations and equivalent, low flow potential relative permeabilities can be predicted during drainage and imbibition, along with trapping characteristics. Equivalent imbibition relative permeabilities appear as a function of capillary number, as in the drainage cases. We also find that the form of capillary pressure function during imbibition has a large impact on the trapping characteristics, with local heterogeneity trapping reduced (or removed), if the capillary pressure drops to zero, or below at the residual saturation

What are the key processes of CO2 storage to represent in energy systems models? A dynamic model of CO2 storage in the UK Bunter Sandstone

Carbon capture and storage (CCS) is expected to play a key role in meeting targets set by the Paris Agreement and for meeting legally binding greenhouse gas emissions targets set within the UK [1]. Energy systems models have been essential in identifying the importance of CCS but they neglect to impose constraints on the availability and use of geologic CO2 storage reservoirs. In this work we analyze reservoir performance sensitivities to increasing average target injection rate, injection site location and varying CO2 storage demand for three sets of injection scenarios designed to encompass the UK\u27s future low carbon energy market. We use the ECLIPSE reservoir simulator and a model of the Southern North Sea Bunter Sandstone saline aquifer. We first find that increasing average target injection does not affect the ability to store CO2, but will be limited by the increase in bottomhole pressure at each site. We find that deeper injection sites will be the least limiting for injection as the near-site lithostatic pressure will be higher [2]. From the first set of varying injection scenarios we find that fluctuating amplitude and frequency of injection has little effect on reservoir pressure response and plume migration. Injectivity varies with site location due to variations in depth and regional permeability. In a second set of injection scenarios, we show that with envisioned UK storage demand levels for a large coal fired power plant, it makes no difference to reservoir response whether all injection sites are deployed upfront or gradually as demand increases. Meanwhile, there may be an advantage to deploying infrastructure in deep sites first in order to meet higher demand later. However, deep-site deployment will incur higher upfront cost than shallow-site deployment. In a third set of injection scenarios, we show that starting injection at a high rate with ramping down, a low rate with ramping up or at a constant rate makes little difference to the overall injectivity of the reservoir. Therefore such variability is not essential to represent CO2 storage in energy systems models resolving plume and pressure evolution over decadal timescales. [1] Future of Carbon Capture and Storage in the UK, UK Parliament House of Commons, Energy and Climate Change Committee, London: The Stationary Office Limited. [2] Agada S., J. S. (2017). The impact of energy systems demands in pressure limited CO2 storage in the Bunter Sandstone. International Journal of Greenhouse Gas Control, (in press)

Integrating Steel Production with Mineral Carbon Sequestration

The objectives of the project were (i) to develop a combination iron oxide production and carbon sequestration plant that will use serpentine ores as the source of iron and the extraction tailings as the storage element for CO2 disposal, (ii) the identification of locations within the US where this process may be implemented and (iii) to create a standardized process to characterize the serpentine deposits in terms of carbon disposal capacity and iron and steel production capacity. The first objective was not accomplished. The research failed to identify a technique to accelerate direct aqueous mineral carbonation, the limiting step in the integration of steel production and carbon sequestration. Objective (ii) was accomplished. It was found that the sequestration potential of the ultramafic resource surfaces in the US and Puerto Rico is approximately 4,647 Gt of CO2 or over 500 years of current US production of CO2. Lastly, a computer model was developed to investigate the impact of various system parameters (recoveries and efficiencies and capacities of different system components) and serpentinite quality as well as incorporation of CO2 from sources outside the steel industry

Real‐time imaging reveals distinct pore scale dynamics during transient and equilibrium subsurface multiphase flow

Many subsurface fluid flows, including the storage of CO2 underground or the production of oil, are transient processes incorporating multiple fluid phases. The fluids are not in equilibrium meaning macroscopic properties such as fluid saturation and pressure vary in space and time. However, these flows are traditionally modeled with equilibrium (or steady-state) flow properties, under the assumption that the pore-scale fluid dynamics are equivalent. In this work, we used fast synchrotron X-ray tomography with 1 s time resolution to image the pore-scale fluid dynamics as the macroscopic flow transitioned to steady state. For nitrogen or decane, and brine injected simultaneously into a porous rock, we observed distinct pore-scale fluid dynamics during transient flow. Transient flow was found to be characterized by intermittent fluid occupancy, whereby flow pathways through the pore space were constantly rearranging. The intermittent fluid occupancy was largest and most frequent when a fluid initially invaded the rock. But as the fluids established an equilibrium the dynamics decreased to either static interfaces between the fluids or small-scale intermittent flow pathways, depending on the capillary number and viscosity ratio. If the fluids were perturbed after an equilibrium was established, by changing the flow rate, the transition to a new equilibrium was quicker than the initial transition. Our observations suggest that transient flows require separate modeling parameters. The time scales required to achieve equilibrium suggest that several meters of an invading plume front will have flow properties controlled by transient pore-scale fluid dynamics

Pore-scale imaging of hydrogen displacement and trapping in porous media

Hydrogen can act as an energy store to balance supply and demand in the renewable energy sector. Hydrogen storage in subsurface porous media could deliver high storage capacities but the volume of recoverable hydrogen is unknown. We imaged the displacement and capillary trapping of hydrogen by brine in a Clashach sandstone core at 2–7 MPa pore fluid pressure using X-ray computed microtomography. Hydrogen saturation obtained during drainage at capillary numbers of &lt;10 −7 was ∼50% of the pore volume and independent of the pore fluid pressure. Hydrogen recovery during secondary imbibition at a capillary number of 2.4 × 10 −6 systematically decreased with pressure, with 80%, 78% and 57% of the initial hydrogen recovered at 2, 5 and 7 MPa, respectively. Injection of brine at increasing capillary numbers up to 9.4 × 10 −6 increased hydrogen recovery. Based on these results, we recommend more shallow, lower pressure sites for future hydrogen storage operations in porous media. </p

The impact of energy systems demands on pressure limited CO2 storage in the Bunter Sandstone of the UK Southern North Sea

National techno-economic pathways to reduce carbon emissions are required for the United Kingdom to meet its decarbonisation obligations as mandated by the Paris Agreement. Analysis using energy systems models indicate that carbon capture and storage is a key technology for the UK to achieve its mitigation targets at lowest cost. There is potential to significantly improve upon the representation of the CO2 storage systems used in these models, but sensitivities of a given reservoir system to future development pathways must be evaluated. To investigate this we generate a range of numerical simulations of CO2 injection into the Bunter Sandstone of the UK Southern North Sea, considered to be one of the most important regional aquifers for CO2 storage. The scenarios investigate the sensitivity of CO2 storage to characteristics of regional development including number of injection sites and target rates of CO2 injection. This enables an evaluation of the impact of a range of deployment possibilities reflecting the range of scenarios that may be explored in an energy system analysis. The results show that limitations in achieving target injection rates are encountered at rates greater than 2 MtCO2/year-site due to local pressure buildup. The areal location of injection sites has minimal impact on the results because the Bunter Sandstone model has good regional connectivity. Rather, the depth of the site is the most important factor controlling limits on CO2 injection due to the relationship between the limiting pressure and the lithostatic pressure gradient. The potential for model simplification is explored by comparison of reservoir simulation with analytical models of average reservoir pressure and near-site pressure. The numerical simulations match average pressure buildup estimated with the “closed-box” analytical model of Zhou et al. (2008) over a 50 year injection period. The pressure buildup at individual sites is estimated using the Mathias et al. (2011) formulation and compared to the simulation response. Discrepancies in the match are mostly due to the interaction of signals from multiple injection sites and heterogeneous permeability in the numerical simulations. These issues should be the focus of further development of simplified models for CO2 storage in an energy systems analysis framework