Visualization of Oil Recovery by Water-Alternating-Gas Injection Using High-Pressure Micromodels

Abstract

Summary The use of WAG (water-alternating-gas) injection can potentially lead to improved oil recovery from the fields. However, there is still an incomplete understanding of the pore-scale physics of the WAG processes and how these lead to improved oil recovery. Simulating the three-phase flow for prediction of the WAG performance in oil reservoirs is an extremely complex process. The existing three-phase relative permeabilities used in simulation are very approximate and do not properly account for the effects of fluid interfacial tension and rock wettability. Network model simulators are being developed to enable the prediction of three-phase relative permeability under different wettability conditions. However, such simulators need to be verified against experimental observations. In this paper, we present experimental results and discussion of a series of capillary-dominated WAG tests carried out in glass micromodels with wettability conditions ranging from water-wet to mixed-wet and oil-wet. Pore level fluid distribution and flow mechanisms were studied, and fluid saturation, at different stages of the experiments, were measured. The results showed that, under any of the wettability conditions, oil recovery by alternating injection of WAG was higher than water or gas injection alone. WAG recovery was observed to be higher for the oil-wet model than that in the mixed-wet one, which in turn was higher than that in the water-wet micromodel. Given enough time and more cycles of WAG injection, the recovery of the mixed-wet model seems to catch up with that of the oil-wet model. Introduction WAG injection is being increasingly applied as an improved oil recovery method, particularly in reservoirs that have been waterflooded. Christensen et al.1 reported a review of some 60 field applications of WAG. Several field trials have been reported as being successful (for instance, in Kuparuk,2 Snorre,3 and Gulfaks fields4). Both immiscible4–6 and miscible gases7 have been used. A large number of coreflood experiments8–12 and analytical and numerical simulations11,13 have been carried out. A study in 1993 demonstrated that the WAG process could be used for improving the hydrocarbon recovery in gas/condensate reservoirs.14 Most of the research work conducted so far has been on either coreflooding8–10 or numerical simulation,11,12 sometimes alongside field trials. The relationship between the injection gas/water ratio (GWR) and oil recovery has been empirically investigated using core displacement experiments, often at low pressure and generally with water-wet cores.8,10 Extensive research is in progress to develop network model simulators that can predict three-phase flow in porous media with immiscible [high interfacial tension (IFT)] and near-miscible (low IFT) fluids and rocks of different wettability. These simulators need to be verified against the experimental observations. This has been carried out to some extent for water-wet systems and using core observations. In the current project, we carry out experiments with micromodels that can be used to obtain an in-depth understanding of the physical processes involved, and to use such information in development and verification of three-phase network model simulators. As far as we know, no micromodel visualization of the WAG injection process has been carried out to directly observe the physical processes taking place in the porous media, using live oil, live water in equilibrium with injection gas, and models with different wettability. Larsen et al.15 reported some results of their WAG micromodel studies. No detail of the experimental procedure and no images of fluid distributions, or recovery results from the micromodel tests, were presented. Etched-glass micromodels are useful for viewing pore level events because of their visual clarity. Micromodels were used as early as 1960 for fluid displacement studies.16 The ability to see the movement of fluid interfaces makes it possible to distinguish between a variety of mechanisms that may take place in a porous medium when more than one phase is present. Chatzis and Dullien17 presented an excellent example of the use of the micromodel to evaluate existing theories of two-phase flow in a simple geometry. Lenormand and Zarcone18 have taken advantage of the well-defined shapes of capillary tubes in their molded resin models to compare the results of calculations of two-phase flow in both drainage and imbibition processes with observation results. Micromodel observations have played a significant role in development of network models for application to multiphase flow. The procedure has been successfully applied to network modeling of two-phase flow in simple or idealized porous media using pore-scale physics identified in micromodel experiments (Lenormand et al.,19 Blunt and King,20 Blunt et al.,21 and Billiote et al.22). In recent years, several advancements in pore-scale modeling have been made. Oren, Bakke, and coworkers23–25 have developed network models based on the pore-space geometry of the rock of interest. The application of network modeling techniques to three-phase flow is considerably less developed than for two-phase flow, especially for oil-wet and mixed-wet porous media. This is because our understanding of the pore-scale physics of three-phase displacement is still incomplete. However, previous micromodel works (Oren and Pinczewski,26 Oren et al.27) suggested that it is possible to learn a great deal about physics of the three-phase displacement in order to take major steps toward developing realistic network models for three-phase flow. For water-wet media, the pore-scale mechanisms are rather well established. But the behavior of oil-wet and mixed-wet systems has a less firm experimental basis. Kovscek et al.28 have provided a pore-level scenario for wettability alteration that has been used to describe fluid configurations of two- and three-phase displacements.29–32 Van Dijke et al.33,34,35 have presented a network model simulator for modeling three-phase flow processes, in particular WAG injection cycles. Using the micromodel results that we presented in two previous papers,36,37 they showed a good agreement between simulation and experiment, in particular with respect to the displacement mechanisms during the WAG cycles. Piri and Blunt38 presented a network model of three-phase flow to capture relative permeabilities, saturation paths, and capillary pressure for media of arbitrary wettability. In this paper, we present a description of the fluid distribution and the pore-scale physics and mechanisms for flow under the WAG processes at different wettability conditions.

Visual Investigation of Improvement in Extra-Heavy Oil Recovery by Borate-Assisted $$\hbox {CO}_{2}$$ CO 2 -Foam Injection

“…7 demonstrate the area in which O/W emulsion formed. Preliminary wettability measurements using the contact angle technique in a similar system with 0.3-0.5 wt% C1 surfactant have shown very strongly water-wet behaviour for un-aged quartz and mica samples (Sohrabi et al 2004). …”

“…Details of the micromodel rig can be found elsewhere (Sohrabi et al 2000(Sohrabi et al , 2001(Sohrabi et al , 2004. A micromodel with a rock-look-alike porous pattern, which had been taken from a thin section photograph of a sandstone rock, was used in this study.…”

Experimental Study and Performance Investigation of Miscible Water-Alternating-CO2Flooding for Enhancing Oil Recovery in the Sarvak Formation

“…The first field application of WAG flooding was done in the North Pembina oil field in Alberta, Canada, by Mobil in 1957 (Christensen et al, 2001;Mirkalaei et al, 2011). The CO 2 -WAG flooding is the combination of the improved volumetric sweep efficiency of water flooding with the enhanced microscopic displacement efficiency of CO 2 flooding, which can lead to a better displacement and an increase of oil recovery compared to continuous CO 2 flooding or water flooding (Christensen et al, 1998(Christensen et al, , 2001Sohrabi et al, 2004;Kulkarni and Rao, 2005;Dehghan et al, 2009;Rouzbeh and Larry, 2010). On the other hand, in the CO 2 -WAG flooding, the injected CO 2 reduces the oil viscosity while water sweeps the mobilized oil to the production well (Ghedan, 2009).…”

Experimental Investigation of Injection Pressure Effect on the Natural Gas Storage in Aquifers

“…Also Chun et al investigated the gas storage process at atmospheric pressure. Sohrabi et al [11] evaluated the multiphase flow and gas phase sweep efficiency during water alternating gas process. Billiotte et al [12] studied numerically the injection withdrawal cycles and the flow rate effect in underground gas storage reservoir, and they have simulated air-water displacement in a micromodel.…”