New insights on the physics of salt precipitation during injection of CO2 into saline aquifers

https://doi.org/10.1016/j.ijggc.2015.10.004Get rights and content

Highlights

  • We performed a series of lab-on-chip experiments to study dynamics of salt precipitation.

  • It is observed that salt can massively precipitate inside the CO2 pathways.

  • Brine is drawn into salt aggregates growing into the CO2 stream due to surface energy effects and the hydrophilic nature of salt.

Abstract

Salt precipitation associated with injection of dry CO2 into saline aquifers has caused reduced injectivity at CO2 storage sites such as Ketzin and Snøhvit. The present-day reservoir scale models of this phenomenon include processes such as evaporation of water into CO2 and capillary backflow of water into the dried zone, and have the salt formation up-scaled to grid-size. However, salt precipitation via these mechanisms has been suggested to only fill a fraction of the pore network and to not significantly affect the permeability. We report lab-on-chip experiments to provide new insights into the dynamics of salt precipitation at the pore-scale and also to find the possible explanations for the large-scale salt precipitation observed in the field. The results of this study introduce two interrelated and so far unreported phenomena –self-enhancing of salt growth and water film salt transport – which together dramatically intensify the precipitation rate and amount of salt precipitated. Our experiments demonstrate that salt crystals, although at different rates, grow in both the liquid and gas phases. Aggregates of micrometer sized crystals in the gas phase create a micro-porous medium with massive capillarity that can strongly imbibe brine over long distances to the evaporation front via capillary connected water films. The imbibed brine in the salt structure is several orders of magnitude thinner than trapped brine in the pores, and due to its high surface area to volume ratio, it rapidly becomes highly super-saturated, leading to a high nucleation rate and the formation of additional salt crystals. The produced salt provides additional surface area for evaporation, and therefore enhances the overall rate of precipitation. This mechanism is active even at extreme CO2 flow rates and therefore salt formation could be more severe than previously concluded, which was based only on core flooding experiments and numerical simulations. The paper raises a serious need for reconsideration of the currently implemented physics in the simulation tools and also for properly designed laboratory experiments, to ensure that the reservoir volume outside the drainage area, which over time contributes to the bulk of precipitated salt, is also included.

Introduction

Carbon capture and storage (CCS) in geological formations is considered as the best near-term solution to mitigate climate changes caused by increasing atmospheric CO2 (Bruant et al., 2002, Bruckner et al., 2014). CCS consists of three connected processes, which are the separation of CO2 from stationary point-source CO2 emission sites, compression and transport to a storage site, and injection into a geological formation, with the intention of long-term isolation from the atmosphere (Benson and Orr, 2008, Metz et al., 2005). The feasibility of CCS has been supported by several successful pilot-scale and commercial-scale projects such as Frio in Texas (Hovorka et al., 2006); Ketzin in Germany (Kiessling et al., 2010); Nagaoka in Japan (Mito et al., 2008); Weyburn in Canada (Preston et al., 2005); Sleipner and Snøhvit in Norway (Maldal and Tappel, 2004, Torp and Gale, 2004); and In Salah in Algeria (Riddiford et al., 2004).

Among the various reservoir options suggested for geological storage of CO2, including depleted oil and gas reservoirs and coal seams, deep saline aquifers are considered the most promising in terms of storage capacity and proximity to emission sources (Bruant et al., 2002, DOE, 2007, IPCC, 2005). However, having a high storage capacity alone is not enough and a potential storage reservoir must meet two other requirements: high, sustainable injectivity and safe containment. Hence, accurate assessment of the formation injectivity is an imperative step in the feasibility study of a CSS project. A combination of technical, economic and political considerations defines the ideal CO2 injection scenario i.e. to store the amount of planned CO2 (based on storage capacity estimations) with the maximum possible injection rate (usually a million tons of CO2 per year) in the shortest possible operational time (between 20 and 30 years), and with the minimum number of drilling wells. CO2 is a reactive fluid and its physical and chemical interactions with the host rock induced by pressure (because of dissolution), temperature (Joule–Thompson effect) and saturation variations (geochemical reactions) make the assessment of injectivity different from petroleum industry experience of non-reactive fluid injection. Formation injectivity is controlled by several factors including absolute and relative permeabilities, formation thickness, well completion, and fluid properties. Among these, formation permeability is the key parameter and has been used in conjunction with reservoir thickness as a preliminary measure of injectivity (Hosa et al., 2010).

During CO2 injection, the permeability in the near-well area might be severely reduced by salt precipitation triggered by the evaporation of brine into the CO2 stream. This induces extra pressure build-up and a decline of injectivity over the course of injection. Field experiences confirm the occurrence of this phenomenon during production/injection from gas reservoirs (Bette and Heinemann, 1989, Kleinitz et al., 2001) and during storage of natural gas (Place and Smith, 1984). Moreover, the source of extra pressure build-up in the Ketzin (Baumann et al., 2014) and Snøhvit (Grude et al., 2014) CO2 storage projects is partly assigned to salt precipitation. Several experimental studies have also observed the precipitation of salt on the core or micro scale (Bacci et al., 2011, Bacci et al., 2013, Kim et al., 2013, Muller et al., 2009, Ott et al., 2011, Ott et al., 2013, Peysson, 2012, Peysson et al., 2011, Peysson et al., 2014, Tang et al., 2014, Wang et al., 2009). Finally, numerical tools have frequently been used to investigate extent, distribution, and physical process associated with this phenomenon (André et al., 2014, Giorgis et al., 2007, Guyant et al., 2015, Hurter et al., 2008, Kim et al., 2012, Liu et al., 2013, Pruess, 2009, Pruess and Müller, 2009, Tang et al., 2014, Wang and Liu, 2013, Zeidouni et al., 2009). The core flooding experiments have shown that a moderate change in porosity (due to salt precipitation) might have a severe effect on permeability, with reported reductions in permeability of 60% (Muller et al., 2009), 30–86% (Bacci et al., 2011), 75% (Ott et al., 2011) and 50% (Peysson et al., 2014) due to halite precipitation in the pore network of Berea sandstone. On the micro-scale, Kim et al. (2013) have reported precipitation of salt crystals in two different forms: (1) large crystals which grow in the liquid phase away from the CO2 interface, and (2) near interface aggregated polycrystalline structures supported by a flow of high-saline brine along thin films driven by capillary forces along the pore channels.

Despite this rather intensive research, a sound physical model for salt precipitation has not yet been developed. Moreover, the obvious inconsistencies between the results of similar experiments make their application to injectivity assessment highly uncertain. Ott et al. (2015) performed flooding experiments using dry supercritical CO2 (scCO2) through a brine saturated Berea sandstone (500 md abs. permeability, 22% porosity) with two different injection rates (2.2 and 4.4 ml/min) and quantified the salt precipitation using X-ray tomography. Local salt accumulation was observed near the injection point at low injection rates, attributed to capillary backflow. For high injection rates, a homogenous precipitation pattern was reported. It was observed that while absolute permeability decreased, effective CO2 permeability in the course of dry-out increased by a factor of five, suggesting little or no change in injectivity. They concluded that salt only precipitated in the volume previously occupied by the trapped brine thus leaving the cross-sectional area of percolation pathways open to CO2 flow. On the other hand, Wang et al. (2009) presented an experimental study of salt precipitation and injectivity impairment during scCO2 injection, also in brine saturated Berea sandstone cores. They used Magnetic Resonance Images (MRI) to visualize halite precipitation behind the dry gas front, and found, contrary to Ott et al. (2015), that the relative permeability to CO2 was reduced by almost half. Discrepancies of this kind are numerous (for example in case of injection rate, salt distribution, capillary pressure, etc.) and demand further research to elucidate. Nevertheless, all the numerical models as well as core flooding experiments agree that for high injection rates (i.e. viscous forces overcome capillary forces) only limited amounts of salt will form, and injectivity will not change by much if at all.

Most of the available experimental and theoretical works have focused on the prediction of the location and the amount of the precipitated salt. However, less attention is given to the characteristics and behaviour of the evaporation front (the interface between brine and the CO2 stream). In the current models, transport of brine to the evaporation front is cut off when the injection rate is high enough to overcome capillary pressure i.e. grain-coating water films are completely vaporized. The resulting salt formation is then limited to the content of salt in the brine vaporized in the CO2 stream. Such a model can hardly explain the considerable reduction of injectivity observed in the field, which would rather require continuous feeding of brine into the CO2 flow zone. We therefore propose that brine can be transported to the evaporation front via capillary continuous water films that cover the reservoir framework grains (mainly quartz). Furthermore, as salt is even more hydrophilic than the framework grain surfaces, we propose that salt precipitation will be enhanced by surface energy effects, through which brine is continuously drawn onto the salt grain surfaces inside the CO2-stream. To evaluate the proposed physical processes, we performed series of pore-scale experiments. Here, micro-chip experiments are a promising tool that can provide insight into the dynamics of salt precipitation at pore-scale and could also help to find possible explanations for the reported discrepancies.

Section snippets

Fabrication and preparation of the micro-chips

In this section, we provide a brief description of key steps involved in fabricating the silicon glass micro-chips. Two flow configurations were fabricated: (1) a two dimensional (2D) network which employed a lattice of square grains (∼500 μm × 500 μm) connected through throats with polygonal cross section of widths 250 μm. This pattern was designed to capture the basic physics associated with flow in the dried region of an aquifer; (2) a single, one dimensional channel (∼2 mm × 100 mm) which is

Homogenous micro-chip experiment

As mentioned in the fabrication section, the first micro-chip was specifically designed to observe salt precipitation and the propagation of the drying front in the drained zone near an injection well. Initially, the chip was fully saturated with brine. Then dry gaseous CO2 was injected at an injection rate of either 0.5 or 50 ml/min. The low injection rate (i.e. 0.5 ml/min or 1.05 mm/s) is chosen to reflect the realistic near wellbore flow rates. However, the high injection rate (i.e. 50 ml/min or

New insights into the physics of salt precipitation

The lab-on-chip experiments in this study introduce two previously unreported physical processes which both enhance the rate and amount of salt precipitation during CO2-injection. Firstly, salt can precipitate inside the CO2 stream, with this precipitation being supported by brine transport along mineral grain surfaces. Secondly, brine is drawn into salt aggregates growing into the CO2 stream due to surface energy effects and the hydrophilic nature of salt, supporting sustained salt

Conclusions

The primary questions investigated were whether trapped water films in porous media have enough continuity and conductivity to transport fresh brine to an evaporating front, and therefore whether these can cause increased rates and quantities of salt precipitation. Using lab-on-a-chip experiments, we have demonstrated the existence of continuous brine films, and we have identified an important, self-enhancing mechanism for the precipitation of aggregates of fine salt grains through rapid

Acknowledgments

This work was partly funded by the Research Council of Norway (RCN) and industry partners through the project 190002/S60 Subsurface storage of CO2 – Injection well management during the operational phase (Inject). The work has also been partly funded by the University of Oslo and the SUCCESS Centre for CO2 storage under grant 193825/S60 from the RCN. The authors gratefully acknowledge Saeed Golshokooh and Vahid Mashayekhizadeh for helps in preparation of the microchips. The author also wishes

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