Foam Flow and Mobility Control in Natural Fracture Networks
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We study the generation and flow of foam through rough-walled, fractured marble rocks that mimic natural fracture systems in carbonate reservoirs. Flow was isolated to the fracture network because of the very low rock permeability of the marble samples and foam generated in situ during co-injection of surfactant solution and gas. The foam apparent viscosities were calculated at steady pressure gradients for a range of gas fractions, and similar to foam flow in porous media, we identified two flow regimes for foam flow in fractures: a high-quality flow regime only dependent on liquid velocity and a low-quality flow regime determined by the gas and liquid velocities. Variations in local fluid saturation during co-injection were visualized and quantified using positron emission tomography combined with computed tomography.
KeywordsFoam generation in fractures Foam apparent viscosity Local fluid flow PET imaging
Fossil fuels are predicted to be a part of the energy mix for the next decades, and enhanced oil recovery (EOR) is necessary to supply the world energy demand. Approximately 60% of all known oil reserves are contained in carbonate reservoirs, which often exhibit significant reservoir heterogeneities, therein fractures (Roehl and Choquette 1985). Fractures combined with oil-wet or mixed-wet reservoir characteristics, often present in carbonate rocks, may cause primary and secondary recovery methods to recover less oil than expected. During water or gas floods, the injected phase will often prefer to flow through the fractures rather than entering into the matrix to displace oil, resulting in poor macroscopic and microscopic sweep, and early breakthrough of the injected phase in production wells. Early breakthrough of gas due to fractures is also highly relevant in developing carbon capture and storage (CCS) projects, where the object is to maximize CO2 storage in underground reservoirs. The effect of pure CO2 injections is greatly reduced when fractures occur, as the CO2 will tend to flow through the highly conductive fractures rather than the matrix (Fernø et al. 2015a, b). Reducing the mobility of gas in fractures, by usage of foams, has potential to greatly improve gas injections in fractured reservoirs, for both EOR and CCS applications. Foams are gas bubbles dispersed in a continuous aqueous phase separated by thin liquid films known as lamellae (Yan et al. 2006). Foam increases the apparent gas viscosity to improve sweep efficiency and oil recovery during gas injections, and has recently been suggested to provide mobility control in fractures and systems featuring large permeability contrasts (Kovscek et al. 1995; Seethepalli et al. 2004; Haugen et al. 2012), with a factor of up to 600 (Buchgraber et al. 2012). Foam generation in fracture systems was previously observed (Fernø et al. 2016; Brattekås and Fernø 2016). Snap-off appears to be the primary mechanisms for generating foam in fractures (Kovscek et al. 1995), and foam generated in fractures differs from foam generated in porous media by having a much larger bubble size. Kovscek et al. (1995) found that bubbles formed in fractures are roughly four times larger than bubbles in foam generated under the same conditions in Berea sandstone, because there are fewer snap-off sites in a fracture than in a porous medium. Foam in fractures is believed to behave as bulk foams (Sheng 2013); however, this might not apply to tight fractures.
Osterloh and Jante (1992) suggested the presence of two flow regimes for foam flooding in porous media: the high-quality, strong foam, regime and the low-quality, weak foam, regime. The regimes are divided by the gas fraction fg*, which position is dependent on the porous medium and the limiting capillary pressure (Pc*). In the strong foam regime (i.e., above fg*), liquid velocity alone controls the flow pressure gradient, while the gas velocity controls the pressure gradient in the weak foam regime. Plotting the pressure gradients as functions of liquid flow rate (x-axis) and gas flow rate (y-axis) forms the “L-plot,” named by the characteristic shape of the pressure contours (Alvarez et al. 2001). The gas fraction for the limiting capillary pressure, fg*, was found to range between 0.94 and 0.96 in porous media (Osterloh and Jante 1992). In fractures, the gas fraction for the limiting capillary pressure may be as high as 0.99 (Pancharoen et al. 2012).
We investigate foam generation and flow in rough-walled fracture networks in marble with varying aperture and at different length scales. Foam is often studied in micromodels or other artificial models of fractured or porous media and less investigated in real rock fractures. Marble is a metamorphic rock made by regional metamorphism of carbonate sediments and has the same surface and mineral composition as sedimentary carbonate rocks. Using marble material to study foam generation and flow through fractures is advantageous: The marble is impermeable with minor porosity, which limits fluid storage and flow in the rock matrix. Hence, fracture flow mechanisms may be studied without contributions from the matrix. The calcite fracture surface ensures liquid–solid interactions similar to sedimentary carbonate rocks, where foam can be applied for enhanced oil recovery (EOR), CCS or aquifer remediation. Surfactant solution and gas were co-injected in different fracture networks, constituting open, partially open and tight fractures. Foam flow in two-dimensional marble fracture networks was previously monitored by direct visual observations (Fernø et al. 2016). Foam was generated during co-injection in a fractured marble tile placed between two transparent plates, and foam propagation and sweep efficiency were monitored directly. In this work, we applied the same materials and fluid systems to generate stable foam with the aim of increasing the complexity of the fracture systems by using three-dimensional marble core plugs of diameters varying from 2.5 to 10 cm (1.5’’-4’’). Foam flow was monitored by differential pressure development, and we used PET-CT imaging to quantify foam behavior in situ. In situ imaging has been extensively used to analyze and quantify fluid transport in porous media. We have previously identified that flow diversion in fracture networks by foam or polymer gels may be visualized and quantified with imaging methods such as CT (Brattekås et al. 2013; Eide et al. 2015; Haugen et al. 2014), MRI (Brattekås and Fernø 2016; Brattekås 2018) and more recently PET-CT (Brattekås et al. 2017; Brattekås and Seright 2018). This paper investigates in situ foam generation and transport through a fracture network, where the marble rock material inhibits fluids diversion into the matrix. We present the approach used to study foam in fractures, and summarize observations and indications from several imaging experiments.
2 Methods and Materials
2.1 Natural Fracture Networks in Marble
2.2 Preparation of Fractured Marble Cores
Overview and properties of the fracture networks
2.2 × 10−6
1.9 × 10−6
14.3 × 10−6
5.1 × 10−6
2.3 Characterization of the Fracture Networks
Fracture networks B, C and E were characterized with positron emission tomography (PET) and X-ray computed tomography (CT) in terms of fracture aperture and degree of heterogeneity and are described in detail below. Two different PET-CT scanners were used. A Siemens Biograph TruePoint medical PET/CT scanner, previously described by Fernø et al. (2015a, b), with a high capacity in terms of weight and size of experimental equipment was used for fracture networks C and E. A preclinical 80 W Nanoscan PC imager, previously described by Brattekås et al. (2017), was used for tight fracture network B.
2.3.1 Tight Fracture Networks
Experimental schedule for the different fracture networks
Baseline and foam co-injections from fg = 1 → 0
Baseline and foam co-injections from fg = 0 → 1
Baseline and foam co-injections from fg = 1 → 0 in PET-CT
Baseline and foam co-injections from fg = 1 → 0.6 in PET-CT
Baseline and foam co-injections from fg = 0.6 → 1 in PET-CT
Baseline and foam injection at different const. vliquid with different vgas
Baseline and foam injection at different const. vgas with different vliquid
Baseline and foam co-injections from fg = 0.4 → 1 in PET-CT
2.3.2 Partially Open Fracture Networks
2.4 Foam Flow in Natural Fracture Networks
Co-injections with gas (Nitrogen) and brine or surfactant solutions were performed in the fracture networks. Injection tests with brine without surfactant present are referred to as baselines: Brine 1 (5 wt% NaCl, 5 wt% CaCl2*2H2O) was used in fracture networks A and B, whereas brine 2 (1 wt% NaCl) was used in fracture networks C, D and E. The brine composition was changed after initial injections using brine 2 in tight fracture systems, where the permeability was observed to increase for long-term injections due to calcite precipitation. In the partially open fracture networks C, D and E, significant changes in permeability were not observed. The surfactant (Huntsman SURFONIC® L24-22) was mixed in synthetic brine 2 (1 wt%) for injection in fracture networks C, D and E.
3 Results and Discussion
3.1 Foam Behavior in Fractures
Foam apparent viscosity in tight fracture networks (A and B) decreased at higher gas fractions (fg = 1.0–0.7) relative to lower gas fractions (fg = 0.5–0.0). Fracture networks A/B (tight) and E (partially open) did not have a continuous longitudinal fracture; rather, individually fractured core plugs were stacked to constitute a fracture system, where each longitudinal fracture was oriented perpendicular to the next (see Figs. 2, 4). In these fracture networks, the apparent foam viscosity was significantly influenced by velocity. In fracture network E, an increase in foam flow velocity by a factor of 1.5 led to an increase in foam apparent viscosity by a factor roughly between 1.6 and 2.2. In network A, a doubling of foam flow velocity increased the apparent foam viscosity by factors between 2 and 4. Due to the partially open fractures in network E, a significantly higher velocity was necessary to obtain high foam viscosities, compared to tight fracture networks. In network C, partially open fractures were oriented in the direction of flow and spanned the entire length of the core, and foam apparent viscosity was not significantly influenced by flow velocities at low to intermediate gas fractions (fg < 0.6). The observations summarized in this section and in Fig. 7 indicate that the type of fracture, specifically the fracture aperture and permeability, influence foam flow. In addition, the orientation of conductive fractures relative to the foam flow direction also seems to have an impact on foam strength, specifically its dependency on flow velocity.
3.2 Can Foam Flow be Visualized Using PET-CT?
In situ imaging was previously used to identify fluid diversion in fractured core plugs during foam injection to improve mobility control and sweep efficiency. Recent combination of advanced medical imaging and dynamic fluid flow identified PET-CT as a highly useful tool to identify fluid flow in fractures (Brattekås et al. 2017; Brattekås and Seright 2018). Here we use CT imaging to characterize complex fracture networks and PET images to quantify foam flow in the fracture networks during co-injections at different gas fractions, by labeling the injected surfactant solution with radioactive 18F-FDG. The PET signal scales linearly with the volume of surfactant solution present, and the PET images could thus be used to study the local spatial saturation of the aqueous phase.
PET also enabled comparison of dynamic foam behavior for different gas fractions, i.e., observation of time-averaged foam behavior to quantify differences between the gas fractions. The PET signal is directly related to the volume of surfactant present, and all scans were normalized to the volume of surfactant injected to enable direct comparison. Thus, the acquisition times for images at higher fg were higher compared to lower fg, at the same volumetric flow rates. The decay of radioactive tracer (half-life 109 min) was accounted for in the image reconstruction software.
3.2.1 PET Imaging of Foam Flow Through Tight Fractures
3.2.2 PET Imaging of Foam Flow in Partially Open Fractures
Fracture network E was constructed similar to fracture networks A and B, where several core plugs with longitudinal fractures were stacked resulting in fractures angled perpendicular to each other along the direction of flow. An important difference was the partially open fractures present in network E that influenced foam strength (Fig. 7). In addition, tight fractures spanned out from the main fracture network in some locations, where fluids could be diverted with improved foam strength.
PET was used to verify foam generation, by observing foam accumulation in transversal fractures. Measured apparent viscosities showed that foam formed in situ in all presented fracture networks.
PET imaging was used to observe average foam properties over several different time intervals, and compare dynamic foam transport through fracture networks using different gas fractions. Average foam properties were stable for a given gas fraction over several different time steps for all fracture networks.
Natural fracture networks with large differences in fracture aperture were not easily analyzed by PET because very high signal in large fractures; thus, signal in closed fractures bears resemblance to noise.
Two foam quality regimes (one high-quality and one low-quality regime) were observed in partially open fractures, and the characteristic L-plot could be generated.
The authors would like to thank the Research Council of Norway for financial support under Grant Number 268216—Nanoparticles to Stabilize CO2-foam for Efficient CCUS in Challenging Reservoirs. The PET-CT imaging was performed at the Molecular Imaging Center (MIC) and was thus supported by the Department of Biomedicine and the Faculty of Medicine and Dentistry, at the University of Bergen, and its partners.
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