Christopher H. Pentland

CO2 wettability of seal and reservoir rocks and the implications for carbon geo‐sequestration

We review the literature data published on the topic of CO2 wettability of storage and seal rocks. We first introduce the concept of wettability and explain why it is important in the context of carbon geo-sequestration (CGS) projects, and review how it is measured. This is done to raise awareness of this parameter in the CGS community, which, as we show later on in this text, may have a dramatic impact on structural and residual trapping of CO2. These two trapping mechanisms would be severely and negatively affected in case of CO2-wet storage and/or seal rock. Overall, at the current state of the art, a substantial amount of work has been completed, and we find that: Sandstone and limestone, plus pure minerals such as quartz, calcite, feldspar, and mica are strongly water wet in a CO2-water system. Oil-wet limestone, oil-wet quartz, or coal is intermediate wet or CO2 wet in a CO2-water system. The contact angle alone is insufficient for predicting capillary pressures in reservoir or seal rocks. The current contact angle data have a large uncertainty. Solid theoretical understanding on a molecular level of rock-CO2-brine interactions is currently limited. In an ideal scenario, all seal and storage rocks in CGS formations are tested for their CO2 wettability. Achieving representative subsurface conditions (especially in terms of the rock surface) in the laboratory is of key importance but also very challenging.

Measurement of Nonwetting-Phase Trapping in Sandpacks

Summary We measure the trapped nonwetting-phase saturation as a function of initial saturation in sandpacks. The application of the work is for carbon dioxide (CO2) storage in aquifers, where capillary trapping is a rapid and effective mechanism to render the injected fluid immobile: The CO2 is injected into the formation followed by chase-brine injection or natural groundwater flow that displaces and traps it. Current models to predict the amount of trapping are based on experiments in consolidated media; while CO2 is likely to be injected at depths greater than approximately 800 m to render it supercritical, it may be injected into formations that tend to have a higher porosity and permeability than deep oilfield rocks. We use analog fluids—water and refined oil—at ambient conditions. The initial conditions are established by injecting oil into vertical or horizontal sandpacks 0.6 m long at different flow rates and then allowing the oil to migrate under gravity. The packs are then flooded with water. The columns are sliced, and the residual saturation is measured with great accuracy and sensitivity by gas chromatography (GC). This method allows low saturations to be measured reliably. The trapped saturation initially rises linearly with initial saturation to a value of approximately 0.13, followed by a constant residual as the initial saturation increases further. This behavior is not predicted by the traditional Land (1968) model but is physically consistent with poorly consolidated media where most of the larger pores can be invaded easily at relatively low saturation and there is, overall, relatively little trapping. The best match to our experimental data is achieved with the Aissaoui (1983) and the Spiteri et al. (2008) trapping models.

Capillary-Trapping Capacity of Sandstones and Sandpacks

This paper (SPE 120960) was accepted for presentation at the EUROPEC/EAGE Conference and Exhibition, Amsterdam, 8–11 June 2009, and revised for publication. Original manuscript received for review 23 February 2009. Revised manuscript received for review 3 December 2010. Paper peer approved 15 April 2011. Summary We quantify the influence of the initial nonwetting-phase saturation and porosity on the residual nonwetting-phase saturation using data in the literature and our own experimental results on sandpacks and consolidated sandstones. These experiments were conducted at ambient or elevated pressure and temperature (ETP) conditions. The principal application of this work is for carbon capture and storage (CCS) where capillary trapping is a rapid and effective way to render the injected CO2 immobile, guaranteeing safe storage. We introduce the concept of capillary-trapping capacity (Ctrap) which is the product of residual saturation and porosity that represents the fraction of the rock volume that can be occupied by a trapped nonwetting phase. We show that the measured trapping capacity reaches a maximum of approximately 11% for porosities of 22%, which suggests an optimal porosity for CO2 storage.

Measurement of Non-Wetting Phase Trapping in Sand Packs

We measure the trapped non-wetting phase saturation as a function of initial saturation in sand packs. The application of the work is for carbon dioxide (CO2) storage in aquifers, where capillary trapping is a rapid and effective mechanism to render the injected fluid immobile: the CO2 is injected into the formation followed by chase brine injection or natural groundwater flow that displaces and traps it. Current models to predict the amount of trapping are based on experiments in consolidated media; while CO2 is likely to be injected at depths greater than around 800 m to render it super-critical, it may be injected into formations that tend to have a higher porosity and permeability than deep oilfield rocks. We use analogue fluids – water and refined oil – at ambient conditions. The initial conditions are established by injecting oil into vertical or horizontal sand packs 1 m long at different flow rates and then allowing the oil to migrate due to buoyancy forces. The packs are then flooded with water. The columns are sliced and the residual saturation measured with great accuracy and sensitivity by gas chromatography. This method allows low saturations to be measured reliably. The trapped saturation initially rises linearly with initial saturation to a value of around 0.11, followed by a constant residual as the initial saturation increases further. This behavior is not predicted by the traditional Land (1968) model, but is physically consistent with poorly consolidated media where most of the larger pores can easily be invaded at relatively low saturation and there is, overall, relatively little trapping. The best match to our experimental data was achieved with the Aissaoui (1983) trapping model. Introduction If we are to avoid potentially dangerous climate change, we need to capture and store CO2 emitted by fossil-fuel burning power stations and other industrial plants (Orr, 2004). Saline aquifers provide the largest potential for storage and the widest geographical spread (Hawkes et al., 2005). Subsequent leakage of CO2 into the atmosphere, even over hundreds of years, would render any sequestration scheme inefficient. However, based on the experience of the oil and gas industry, there is a good understanding of trapping mechanisms that take place in geological formations. Hydrodynamic trapping is the primary mechanism by which hydrocarbons accumulate in the subsurface. The same mechanism would take place during carbon sequestration, with the less dense CO2 rising due to buoyancy forces until it is trapped under impermeable cap-rock (Bachu et al., 1994). However, this process relies on there being an intact barrier to upwards flow. Solution trapping occurs when there is dissolution of CO2 in the aquifer brine. The CO2 saturated brine is denser than the surrounding brine leading to convective mixing where the denser brine migrates deeper into the formation (Lindeberg and Wessel-Berg, 1997; Riaz et al., 2006; Ennis-King and Paterson, 2005). Mineral trapping occurs over longer timescales than other trapping methods. As CO2 dissolves in formation brine carbonic acid is formed (H2CO3) which dissociates and can subsequently react with the host rock or brine to generate solid minerals over periods of thousands to billions of years (Gunter and Perkins, 1993; Gunter et al., 1997; Egermann et al., 2005; Lin et al., 2008). The final trapping mechanism involves CO2 becoming immobile at the pore scale by capillary forces. This process occurs as the CO2 migrates upwards, when it is displaced by natural groundwater flow or by the injection of chase brine. It is a rapid and effective trapping mechanism that reduces the need to ensure cap-rock integrity (Kumar et al., 2005; Hesse et al., 2006; Obi and Blunt, 2006; Juanes et al., 2006; Qi et al., 2007; Saadatpoor et al., 2008).

Measurements of Non-Wetting Phase Trapping Applied to Carbon Dioxide Storage

Abstract We measure the trapped non-wetting phase saturation as a function of the initial saturation in sand packs. The application of the work is for carbon dioxide (CO 2 ) storage in aquifers where capillary trapping is a rapid and effective mechanism to render injected CO 2 immobile. We used analogue fluids at ambient conditions. The trapped saturation initially rises linearly with initial saturation to a value of 0.11 for oil/water systems and 0.14 for gas/water systems. There then follows a region where the residual saturation is constant with further increases in initial saturation.

Capillary Trapping in Carbonate Rocks

Carbonate reservoirs represent a possible geological storage option for carbon dioxide from anthropogenic sources. We conducted capillary trapping experiments on different carbonate rocks to assess their suitability for storage. We measured the trapped non-wetting phase saturation as a function of the initial non-wetting phase saturation and porosity. We used refined oil – with a density similar to that of supercritical CO2 – as the non-wetting phase and brine as the wetting phase. The experiments were performed at ambient temperature and slightly elevated pressures. Saturations were determined by mass and volume balance. We found that the trapped non-wetting phase saturation rises approximately linearly with initial saturation. The porosity was shown to have a significant effect on both initial saturation and residual saturation.The influence of effective stress was also investigated. It was shown that carbonates have significantly different stress behavior compared to sandstones. As the pressure of the non-wetting phase increases during primary drainage, the initial oil saturation increases to a maximum value and then decreases, as the fluid pressure affects the pore structure of the rock.

Residual Saturation of Water-Wet Sandstones: Experiments, Correlations and Pore-Scale Modeling

Displacement experiments using the porous plate method were conducted on water-wet sandstones to measure the capillary trapping of oil by waterflooding as a function of its saturation after primary drainage. Three sandstone samples ranging in porosity from 12.2% to 22.1% were considered. Experiments on two samples were conducted at an elevated temperature and back-pressure of 343K and 9MPa respectively; experiments on the third sample were conducted at ambient conditions (292 to 297K and 0.06 to 0.17MPa). Residual oil saturation increases monotonically, but with a decreasing gradient, as initial saturation increases.

Three Phase Measurements of Nonwetting Phase Trapping in Unconsolidated Sand Packs

We perform a series of experiments in water-wet sand packs to measure the trapped saturations of oil and gas as a function of initial saturation. We start with brine-saturated columns and inject octane (oil) to reach irreducible water saturation followed by displacement by air (gas) from the top, allowing oil and air to drain under gravity for different amounts of time, then finally brine is injected from the bottom to trap both oil and gas. The columns are sliced and a sensitive and accurate measurement of saturation along the column is made using gas chromatography. The maximum residual gas saturation is over 20%, compared to 14% for two-phase flow (Al Mansoori et al. 2009). For lower initial gas saturation, the amount of trapping is similar to that reached in an equivalent two-phase experiment. We also find that the amount of oil trapped is insensitive to either the initial gas saturation or the amount of gas that is trapped. More oil is trapped than would be predicted from an equivalent two-phase system, although the trapped saturation is never larger than the maximum reached in two-phase flow (around 11%) (Pentland et al. 2008). These initially surprising results are explained in the context of oil layer stability and the competition between snap-off and piston-like advance. In unconsolidated two-phase water-wet systems, displacement is principally by cooperative piston-like advance with relatively little trapping, whereas in consolidated media snap-off is generally more significant. However, during three-phase waterflooding, oil layer collapse events rapidly trap the oil which acts as a barrier to direct water-gas displacement, except by snap-off, leading to enhanced gas trapping. Introduction The motivation of this research is to understand trapping of CO2 in carbon capture and storage projects, although the work also has application to enhanced oil recovery processes. Capillary trapping as been proposed as a rapid and effective way to store CO2 securely in simulation studies (Flett et al. 2004; Kumar et al. 2005; Hesse et al. 2006; Juanes et al. 2006; Obi et al. 2006; Hesse et al. 2008; Juanes et al. 2008; Saadatpoor et al. 2008; Qi et al. 2009). In this paper, we focus on CO2 capillary trapping in aquifers and oilfields through analogue laboratory experiments in water-wet systems. It is already well established that in drainage displacements, where gas displaces oil and water, very low residual oil saturations can be achieved in sand-packs similar to those we study here (see, for instance, Sahni et al. 1998; Dicarlo et al. 2000a;b). Here, however, we will study situations where the final displacement is a waterflood, trapping both oil and gas. Previous work (Holmgren et al. 1951; Kyte et al. 1956; MacAllister et al. 1993; Skauge 1996; Egermann et al. 2000) has shown that the residual oil saturation in three-phase flow is reduced from its two-phase value (where no trapped gas is present): p 3 gr p 2 or p 3 or S a S S − = (1) where p 3 gr S is the residual gas saturation in the presence of oil and water, p 3 or S is the residual oil saturation after waterflooding in the presence of gas, and p 2 or S is the residual oil saturation after two-phase waterflooding with no gas present. Water-wet data from Holmgren and Morse (1951) and Kyte et al. (1956) suggest that the coefficient a is 0.45. Egermann et al. (2000) reported similar results. Kyte et al. (1956) also reported data for Alundum rendered oil-wet by drifilm that indicates that a = 0. Skauge (1996) measured values of 0.5 to 1 for water-wet systems, 1 for weakly water-wet, and 0 for oil-wet systems. Data from MacAllister et al. (1993) for Baker dolomite indicate that a is 0.75, 0.25 and 0.04 for waterwet, mixed-wet and oil-wet conditions respectively. Kralik et al. (2000) found a = 0 for oil-wet media. Caubit et al. (2004)