Low salinity waterflood (LSW) is a relatively new enhanced oil recovery (EOR) technique which has been reported to improve oil recovery in several laboratory experiments and some field trials. The general assumption among researchers is that LSW shifts wettability towards a more favourable state for oil recovery. Several hypotheses have been introduced in the literature as possible mechanisms involved in oil recovery by LSW e.g. fine migration and flow diversion, multi-component ion exchange (MIE), and rise in pH. However, a consistent theory to explain the process of wettability modification has not yet emerged. This paper presents the results of a comprehensive set of direct visualization (micromodel) experiments which investigate the low salinity effect (LSE) from a novel perspective. The visualization study, using reservoir-condition micromodels, shows that when low salinity brine comes in contact with certain crude oils, a large number of water micro-dispersions form at the oil/water interface within the oil phase. The formation and precipitation of these micro-dispersions can only be seen under high magnifications using our imaging system specifically designed for thin micromodels. The water micro-dispersions do not form when the oil is in contact with a high salinity brine and when they form due to low salinity of the brine, they coalescence as soon as the oil comes in contact with a high salinity brine. In our micromodel tests, when a mixed-wet micromodel and high salinity connate water were utilized, the formation of these micro-dispersions was associated with a slight change in the wettability and redistribution of fluids. We hypothesize that formation of the micro-dispersions results in additional oil recovery through two separate mechanisms; (1) depletion of the oil/water interface from natural surface active materials, resulting in wettability alteration and, (2) swelling of droplets of high salinity connate water. The results of this study introduce water/oil interactions and formation of water micro-dispersions as a potential mechanism for wettability alteration and improved oil recovery in low salinity water injection.

Carbonated (CO 2 -enriched) water injection has been shown to improve waterflood performance over conventional water flood. Carbonated water can be purposely injected in an oil reservoir but it also forms spontaneously during conventional CO 2 floods or CO 2 WAG injection. It is therefore important to understand the rock-fluid and fluid-fluid interactions that take place in an oil reservoir when carbonated water contacts the oil and the reservoir rock. Due to dissolution of CO 2 in brine, the pH of injection water is reduced during carbonated water injection. This reduction in brine pH may affect the electric charges on water-rock interfaces and hence, may alter the wetting characteristics of the surface. This wettability alteration will have a direct effect on oil recovery and the amount of oil remaining after waterflood.In order to assess and quantify the extent of possible wettability alteration due to carbonation of water a series of contact angle measurements have been performed in this study. Three different minerals namely; Quarts, Mica, and Calcite were exposed to plain and then carbonated water under a wide range of pressures between 100 and 3500 psi. The temperature of the measurements was kept constant at 100 ⁰F. For each mineral, two situations were considered; an un-aged (clean) rock system and an aged rock system. The captive bubble method was used for measuring the contact angles.The results for the un-aged measurements show that carbonated water can change the wettability of clean minerals in varying degrees. The observed change in the measured contact angles was a function of pressure and it increased as the pressures increased. For the un-aged substrates, the change in wettability by carbonated water was moderate with the maximum change of around 6 degrees taking place for Quartz.The results of the aged minerals revealed a much higher change in wettability by carbonated water compared to the un-aged substrates. For the aged quartz sample, at the pressure of 2500 psi, when CO 2 was introduced to the top of plain brine and CW was formed, the contact angle changed from 76 to 61, and for the aged mica at the same pressure the contact angle changed from 89 to 63. For the aged Calcite, carbonated water brought about a larger change in wettability with the contact angle changing from 144 to 97.The results of the study show that under real reservoir conditions where the rock is usually mixed-wet or oil-wet, the dissolved CO 2 content of water can have a major impact on the wettability of the reservoir, which in turn would significantly affect the oil displacement efficiency and the recovery factor.

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.

The benefits and advantages of waterflood are well-known with many decades of application in a wide range of reservoirs with different crude oil and rock types. However, the average global recover factor for waterflood is only around 30%. There is, therefore, great interest in developing methods that can augment waterflood and improve its recovery factor from the current low values. It has been shown that enriching water with CO2 and injecting it in the form of carbonated water can improve the performance of water flood significantly 1-15. However, a complete understanding of the pore-scale interactions and events taking place during carbonated water injection (CWI) in an oil reservoir and the actual mechanisms by which additional oil may be recovered are still missing and therefore the true potential of CWI is not yet well known. This is further complicated by the fact that the current commercial reservoir simulators are not able to adequately simulate the complex and multi-physics processes that take place during CWI which include both fluid/fluid and rock/fluid interactions. The objective of the Carbonated Water Injection (CWI) JIP at Heriot-Watt University is to perform a thorough investigation of the performance of CWI under reservoir conditions and systematically study the parameters that impact the amount of oil recovery by CWI and its underlying mechanisms. Here we present the results of a series of CWI experiments performed under reservoir conditions at pore-scale and core-scale. Direct flow visualisation results of our high-pressure micromodel experiments reveal very vividly the pore-scale events that take place as CO2 gradually leaves the injected carbonated water and dissolves in the oil. The results show that the pore-scale interactions of carbonated water with crude oil are quite different from the well-known mechanisms observed in conventional CO2 flood. Apart from the usual CO2-related mechanisms such as oil swelling and viscosity reduction, in CWI, formation of a new fluid phase within the oil is observed. As we will show, this is a major mechanism that significantly improves the performance of CWI and the amount of additional oil recovery achieved by CWI. Our coreflood experiments confirm our pore-scale flow visualization results and clearly show that, compared to conventional waterflood, CWI can lead to substantial additional oil recovery under both secondary mode (injected instead of conventional water flood) and tertiary mode (injected after conventional water flood). The performance of CWI is significantly affected by the composition of the oil including the amount of light and intermediate hydrocarbons dissolved (solution gas) in crude oil.

Carbon dioxide (CO 2 ) injection is a well-established method for increasing recovery from oil reservoirs. However, poor sweep efficiency has been reported in many CO 2 injection projects due to the high mobility contrast between CO 2 and oil and water. Various injection strategies including gravity stable, WAG and SWAG have been suggested and, to some extent, applied in the field to alleviate this problem. An alternative injection strategy is carbonated water injection (CWI). In CWI, CO 2 is delivered to a much larger part of the reservoir compared to direct CO 2 injection due to a much improved sweep efficiency. In CWI, CO 2 is used efficiently and much less CO 2 is required compared to conventional CO 2 flooding, and hence the process is particularly attractive for reservoirs with limited access to large quantities of CO 2 (offshore reservoirs or reservoirs far away from inexpensive natural CO 2 resources). This article describes the results of a pore-scale study of the process of CWI by performing high-pressure visualisation flow experiments. The experimental results show that CWI, compared to unadulterated (conventional) water injection, improves oil recovery as both a secondary (before water flooding) and a tertiary (after water flooding) recovery method. The mechanisms of oil recovery by CWI include oil swelling, coalescence of the isolated oil ganglia and flow diversion due to flow restriction in some of the pores as a result of oil swelling and the resultant fluid redistribution. In this article the potential benefit of a subsequent depressurisation period on oil recovery after the CWI period is also investigated.

Summary The underlying mechanism of oil recovery by low-salinity-water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature, but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct-flow-visualization investigations (Emadi and Sohrabi 2013) have revealed that a physical phenomenon takes place when certain crude oils are contacted by low-salinity water, leading to a spontaneous formation of micelles that can be seen in the form of microdispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude-oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include direct-flow (micromodel) visualization, crude-oil characterization, coreflooding, and spontaneous-imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface-active components of crude oil, and the improvement in oil recovery because of LSWI. We present the results of a series of spontaneous- and forced-imbibition experiments carefully designed with reservoir cores to investigate the role of the microdispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing an LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared with high-salinity-water injection (HSWI) in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude-oil/brine-interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicate that the natural surface-active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research can be applied to oil recovery from both sandstone and carbonate oil reservoirs because they are mainly derived from fluid/fluid interactions that control wettability alteration in both sandstone and carbonate rocks.

Carbonated water injection (CWI) is a CO 2 -augmented water injection strategy that leads to increased oil recovery with added advantage of safe storage of CO 2 in oil reservoirs. In CWI, CO 2 is used efficiently (compared to conventional CO 2 injection) and hence it is particularly attractive for reservoirs with limited access to large quantities of CO 2 , e.g. offshore reservoirs or reservoirs far from large sources of CO 2 . We present the results of a series of CWI coreflood experiments using water-wet and mixed-wet Clashach sandstone cores and a reservoir core with light oil (n-decane), refined viscous oil and a stock-tank crude oil. The experiments were carried out to assess the performance of CWI and to quantify the level of additional oil recovery and CO 2 storage under various experimental conditions. We show that the ultimate oil recovery by CWI is higher than the conventional water flooding in both secondary and tertiary recovery methods. Oil swelling as a result of CO 2 diffusion into the oil and the subsequent oil viscosity reduction and coalescence of the isolated oil ganglia are amongst the main mechanisms of oil recovery by CWI that were observed through the visualisation experiments in high-pressure glass micromodels. There was also evidence of a change in the rock wettability that could also influence the oil recovery. The coreflood test results also reveal that the CWI performance is influenced by oil viscosity, core wettability and the brine salinity. Higher oil recovery was obtained with the mixed-wet core than the water-wet core, with light oil than with the viscous oil and low salinity carbonated brine than high-salinity carbonated brine. At the end of the flooding period, an encouraging amount of the injected CO 2 was stored in the brine and the remaining oil in the form of stable dissolved CO 2 . The experimental results clearly demonstrate the potential of CWI for improving oil recovery as compared with the conventional water flooding (secondary recovery) or as a water-based EOR (enhanced oil recovery) method for watered out reservoirs.

As gas flooding becomes a more viable means of enhanced oil recovery, it is important to identify and understand the pore-scale flow mechanisms, both for the development of improved gas flooding applications and for the predicting phase mobilisation under secondary and tertiary gas flooding. The purpose of this study was to visually investigate the pore-level mechanisms of oil recovery by near-miscible secondary and tertiary gas floods. High-pressure glass micromodels and model fluids representing a near-miscible fluid system were used for the flow experiments. A new pore-scale recovery mechanism was identified which significantly contributed to oil recovery through enhanced flow and cross-flow between the bypassed pores and the injected gas. This mechanism is strongly related to a very low gas/oil interfacial tension (IFT), perfect wetting conditions and simultaneous flow of gas and oil in the same pore, all of which occur as the gas/oil critical point is approached. The results of this study helps us to better understand the pore-scale mechanisms of oil recovery in very low-IFT (near-miscible) systems. In particular we show that in near-miscible gas floods, behind the main gas front, the recovery of the oil continues by cross-flow from the bypassed pores into the main flow stream and as a result almost all of the oil, which has been contacted by the gas, could be recovered. Our observations in high-pressure micromodel experiments have demonstrated that this mechanism can only occur in near-miscible processes (as opposed to immiscible and completely miscible processes), which makes oil displacement by near-miscible gas floods a very effective process.