Application of polymer flooding as a chemical Enhanced Oil Recovery (EOR) has increased over recent years. The main type of polymer used is partially hydrolyzed polyacrylamide (HPAM). This polymer still has some challenges especially with shear stability and injectivity that restrict its utility, particularly for low permeability reservoirs. Injectivity limits the possible gain by acceleration in oil production due to polymer flooding. Hence, good polymer injectivity is a requirement for the success of the operation. This paper aims to investigate the influence of formation permeability on polymer flow in porous media.
In this study, a combination of core flooding with rheological studies is presented to evaluate the influence of permeability on polymer in-situ rheology behavior. The in-situ flow of HPAM polymers has also been studied for different molecular weights. The effect of polymer preconditioning prior to injection was studied through exposing polymer solutions to different extent of mechanical degradation.
Results from this study reveal that the expected shear thinning behavior of HPAM that is observed in rheometer measurements is not observed in in-situ rheology in porous media. Instead, HPAM in porous media exhibits near-Newtonian behavior at low flow rates representative of velocities deep in the reservoir, while exhibiting shear thickening behavior at high flow rates representative of velocities near wellbore region. The pressure build-up associated with shear thickening behavior during polymer injection is significantly higher than pressure differential during water injection. The extent of shear thickening is high during the injection of high Mw polymer regardless of cores' permeability. In low permeable Berea cores, shear thickening and mechanical degradation occur at lower velocities although the degree of shear thickening is lower in Berea to that observed in high permeable Bentheimer cores. This is ascribed to high polymer retention in Berea cores that results in high residual resistance factor (RRF). Results show that preshearing polymer before injection into porous media optimizes its injectability and transportability through porous media. The effect of preshearing becomes favorable for the injection of high Mw polymers into low permeability formation.
This study discusses polymer in-situ rheology and injectivity, which is a key issue in the design of polymer flood projects. The results provide beneficial information on optimizing polymer injectivity, in particular, for low permeability porous media.
CO2 Water-Alternating-Gas injection (CO2 WAG), which involves complex phase and flow behaviour, is still a challenging task to simulate and predict accurately. In this paper, we focus specifically on the regime of viscous fingering flow in CO2 WAG in heterogeneous systems because of its importance. We investigated two key physical processes that occur during near-Miscible WAG (nMWAG) processes, namely oil stripping (Mechanism 1, M1) and low-interfacial-tension (IFT) film flow effects (Mechanism 2, M2). The low IFT effects in M2 manifest themselves in an increased mobility of oil phase due to film flow process (discussed below). The importance of properly simulating the interaction of viscous, compositional (M1), and low-interfacial-tension effects (M2) is clearly demonstrated in this study. Our specific aim is to improve the modelling of CO2 displacement in the transition from immiscible to miscible flows in CO2 WAG processes.
We simulated both immiscible and near-miscible CO2 WAG and also continuous CO2 displacements with unfavourable mobility ratios for 1D and 2D systems. 2D heterogeneous permeability fields were generated with certain Dykstra-Parsons coefficients and dimensionless correlation ranges. IFT (σgo) was calculated by the simulator as part of the compositional simulation using the McLeod-Sugden equation. The consequent IFT effects on relative permeability was imposed using two commonly used models, i.e.
We tested various combinations of oil-stripping effects (M1) and IFT effects (M2) to evaluate the potential impact of each mechanism on the flow behaviour such as the local displacement efficiency, the tracking of tracer flow and the ultimate oil recovery. Oil bypassed by viscous fingering/local heterogeneity, can be efficiently recovered by WAG in the cases where both M1 and M2 are taken into account (as opposed to either mechanism being considered alone). Through tracer analysis, we found that a major recovery mechanism in near-miscible displacement was
Polymer flooding has been widely applied through past decades to increase oil recovery after waterflood. Water-soluble polymers are used to increase the viscosity of injected water that is a requirement for better sweep efficiency, but accelerated production due to polymer flooding may be limited by reduced injectivity. The objective of this paper is to give guidelines for optimizing polymer injectivity as key parameter for polymer flooding design.
Analysis of polymer injection data from field tests, and different analytical and simulation approaches from academic or commercial simulators will be discussed. Field realistic laboratory flooding in porous medium has been performed. Presented experiments study the influence of preinjection treatment like pre-shearing or other methods on rheological properties in porous medium. Injectivity is discussed in relation to polymer molecular weight, polymer concentration, pre-treatment, and presence of oil.
Field scale injectivity is reviewed from available literature data. Impact of fracturing has been analyzed in order to isolate the matrix impact on injectivity and compare to laboratory data. Investigations show that injection pressure build up in the near wellbore region, which is also referred to as polymer shear thickening behavior, limits the injectivity of polymer solutions. The effect is more significant when high molecular weight polymer is injected compared to high polymer concentration. Hence, pre-shearing the polymer solution prior injection weakens the elastic properties of polymer while maintaining its viscous properties. Also, better polymer injectivity observed when oil is present (two phase flow) in porous media compared to no oil present (one phase flow).
This paper will discuss polymer injectivity and isolate key parameters for optimizing injectivity. The data from this study gives guidelines for optimizing polymer injectivity.
Polymer flooding is a broadly applied enhanced oil recovery (EOR) method. Its application gains an interest especially in current oil prices (Seright, 2016). Polymer flooding with better mobility ratio improves sweep efficiency compared to conventional waterflooding (Skauge et al., 2014). Generally, two categories of polymers are used in EOR applications. These are biopolymers such as xanthan and synthetic polymers such as hydrolyzed polyacrylamide (HPAM). HPAM polymers are the main focus in this study. Polymer flooding by HPAM shows success in different oil recovery applications both onshore and offshore at different reservoir formations e.g., sandstone, carbonates and dolomite (Standnes and Skjevrak, 2014). HPAM is also involved in other chemical EOR applications such as Low Salinity Polymer (LSP) (Skauge and Shiran, 2013, Unsal et al., 2017) and Alkaline Surfactant Polymer (ASP) flooding (Olajire, 2014).
Experiments on injection of composite EOR fluids, simultaneously or sequentially, have been validated by small scale simulation, with cell sizes in the millimeter-range. The injected fluids have been a combination of low-salinity brine, surfactant, and polymer. This presentation addresses the challenges of extending the lab scale results to larger models, up to field size.
The complex injection scheme itself is not straightforward to model in any simulator, and novel techniques have been developed to handle this. The main mechanisms that must be addressed are concentration dependent properties for all fluids involved and any combination of these, e.g. relative permeability and viscosity. The methods used have been adapted to both a black oil simulator, and a composition based simulator. As the basic modeling principles for black oil and compositional simulators are per se very different, the way of handling fluid descriptions from the user view point are naturally quite different for the two approaches. Hence also adaption to the composite processes necessarily differs.
History matching (validating) experiments at lab scale was successfully done with both simulators, with qualitative equal though not identical results. When attempting to generalize results to larger models, two issues have been addressed;
One magnitude that had to be focused on was simulated pressure. Simulated injection pressure and resulting average pressure during polymer injection was not in agreement with field observations, probably because the simulators do not include all the complex mechanisms of polymer flood. Hence maintaining reservoir pressure within a reasonable range during simulation turned out to be a challenge, especially for the black oil simulations.
In conclusion it was found that with the appropriate approach, robust and reliable results could be obtained at scales less than some critical value, consistent with similar results obtained for pure water flood simulations. Compositional simulations were apparently more reliably scaled than black oil simulations. An important finding was that results were extremely sensitive to correct and consistent definition of fluid descriptions, and users must be aware of different approach angles for compositional and black oil simulators in this respect.
Wettability of the reservoir is a major parameter controlling the oil production profile during waterflooding, the breakthrough of injection water, the final oil recovery, and the residual oil saturation (Sor) trapped in the pore structure. Therefore identifying the wettability of the reservoir will lead to appropriate implementation of improved/enhanced oil recovery practices in order to improve the economy of the project.
The initial wettability state of the reservoir rock has crucial impact on the performance of polymer flooding process. Polymer flow behavior in the porous media including pressure build up, polymer retention due to adsorption mechanism, resistance factor, and residual resistance factor can be affected by wettability of the porous media. This, in turn, would affect the technical and economic success or failure of the polymer flooding project. Unfortunately, in the petroleum literature there is very little data regarding the effect of wettability on oil recovery by polymer flooding.
In this paper we investigate the propagation of polymer and polymer particles under different wettability states. The flow behavior of polymer solution including pressure build up, resistance factor (Fr), and residual resistance factor (Frr) are compared at different wettability states. Moreover the oil recovery efficiency by polymer flooding at different wettability states is presented in this paper.
Skauge, Tormod (CIPR, Uni Research) | Vik, Bartek Florczyk (CIPR, Uni Research) | Ormehaug, Per Arne (CIPR, Uni Research) | Jatten, Berit K. (CIPR, Uni Research) | Kippe, Vegard (Statoil ASA) | Skjevrak, Ingun (Statoil ASA) | Standnes, Dag Chun (Statoil ASA) | Uleberg, Knut (Statoil ASA) | Skauge, Arne (CIPR, Uni Research)
Polymer flooding is a mature EOR technology, but several pore scale phenomena with large influence on the reservoir scale are poorly understood. This paper describes and analyses oil mobilization experiments of heavy oils by imaging instable displacement at adverse mobility ratio water and polymer floods. Two-dimensional flood experiments have been performed using Bentheimer outcrop slabs. X-ray imaging is utilized to visualize displacements and to determine the underlying flow mechanisms. Viscous fingering, water channel formation and oil displacement is described for a series of mobility ratios.
Mechanistic understanding of development and propagation of viscous fingers at adverse mobility ratio may be used to improve reservoir simulations. Description of oil mobilization for various mobility ratios may give guidelines for choice of polymer concentration and slug size for polymer floods.
Bentheimer slabs were drained using oils with 4 viscosities (8 - 834 mPas). X-ray imaging revealed differences in water-finger formation, and width and growth of fingers with increasing mobility ratio. Lower mobility ratios showed formation of wide fingers or water channels. Oil recovery was dominated by propagation of these channels, but still showed poor sweep efficiency (water breakthrough 0.3 – 0.5 PV). At high mobility ratio, water breakthrough occurred very early at 0.08 – 0. 15 PV. Here, the oil recovery mechanism was totally different. Oil was mobilized by polymer injection through cross-flow into the water channels. Polymer flood showed rapid change in oil cut and high total oil recovery efficiency. Through analysis of 2D x-ray images, mechanisms for fingering initiation and propagation and for oil mobilization by polymer is visualized and discussed as a function of mobility ratio.
The results presented here impact polymer flood design, particularly for choice of polymer injection strategy for heavy oil reservoirs. Data show that relatively low polymer concentrations are sufficient for mobilizing heavy oil.
Numerical simulation of any EOR process is a key to the prediction of incremental oil recovery. Water -alternating -gas (WAG) injection has found an increasing interest for both clastic and carbonate reservoirs and both miscible and immiscible gas conditions.
WAG injection is an oil recovery method initially aimed to improve sweep during gas injection. Possible improved microscopic efficiency in three-phase zones of the reservoir may come as an added benefit from the WAG injection. Today the WAG process (both miscible and immiscible) is considered for a number of new fields in the North Sea. WAG is defined as any injection of both water and gas into the same reservoir. This including definition covers MWAG (miscible), IWAG (immiscible), HWAG (hybrid), SWAG (simultaneous), and also tertiary gas injection or tertiary water flooding.
The paper reviews recent development in modelling of immiscible and miscible WAG processes. Several different approaches have been made to model three-phase relative permeability in particular. In most cases capillary pressure has been neglected in application of these models in numerical simulations of IWAG. The argument behind eliminating capillary pressure is to simplify the model, and the assumption that capillary pressure is of less importance for the problem analysed or because there are no experimental data available. The results given will show the consequence of neglecting capillary pressure. Fluid flow functions for
miscible WAG will also be described in details.
In CO2 projects for enhanced oil recovery (EOR) a critical factor is possible early CO2 breakthrough and consequently poor sweep efficiency. Injection of foam can block and divert CO2 which may improve sweep efficiency.
Large changes in physical properties of CO2 with temperature and pressure might affect CO2-foam performance under various reservoir conditions. Recently, we have focused on understanding supercritical CO2-foam properties and this paper describes the importance of supercritical CO2 density on CO2-foam performance in outcrop Berea sandstone core material.
Foam flooding experiments were conducted in sandstone core material at different pressures from 30 to 280 bar and at temperatures of 50 and 90°C using an AOSC14/16 surfactant. Results showed high foam strengths at low CO2 density. In fact, the strongest supercritical CO2-foam was generated at the lowest supercritical CO2 density tested, quite comparable to foam strength obtained with gaseous CO2. Only reduced foam strengths were found with dense supercritical CO2 (MRF 3-11).
Foam generation was studied with both equilibrated and non-equilibrated fluids. Previously, we showed that CO2-foam stability and blocking ability were strongly reduced when mass transfer occured. In this study delay in foam strength build-up was observed with non-equilibrated fluids. In addition, visual observations of the foam texture indicated larger bubbles.
Compared to N2-foams at similar conditions CO2-foams were weaker and showed coarser foam structure.
Low salinity water flooding is well studied for sandstone reservoirs, both laboratory and field tests have showed improvement in the oil recovery in many cases. Up to very recently, the low salinity effect has been indeterminated for carbonates. Most recently, Saudi Aramco reported that substantial additional oil recovery can be achieved when successively flooding composite carbonate core plugs with various diluted versions of seawater. The experimental data on carbonates is very limited, so more data and better understanding of the mechanisms involved is needed to utilize this method for carbonate reservoirs.
In this paper, we have experimentally investigated the oil recovery potential of low salinity water flooding for carbonate rocks. We used both reservoir carbonate and outcrop chalk core plugs. The flooding experiments were carried out initially with the seawater, and afterwards additional oil recovery was evaluated by sequential injection of various diluted seawater. The experiments applied stepwise increase in flow rate to eliminate the influence of possible capillary end effect. The total oil recovery, interaction of the different ions with the rock, and the wettability changes were studied both at ambient and high temperature.
No low salinity effect was observed for the reservoir carbonate core plug at the ambient temperature, but increase of the pressure drop over the core plug was detected. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the reservoir carbonate core plugs at 90 °C. An increase in pressure drop was also observed in this case, possibly related to migration of fines or dissolution reactions. The outcrop Aalborg chalk core plugs did not show any low salinity effect, both at the room and at a high temperature. In the light of experimental results, discussions are made about possible mechanisms for improving oil recovery in carbonate reservoir as a function of change in brine salinity.
Low salinity has been studied extensively, but still the mechanisms for improved oil recovery by lowering brine salinity are unsolved. The target of this paper was to address this problem and make systematic studies that can give insight to the key mechanisms. Given the variety of conditions under which increased recovery by low salinity brine injection may or may not be observed, it is likely that more than one mechanism is contributing to the observed oil recovery. The mechanisms most claimed to be the reason for improved oil recovery are shift in wettability, multi-component ion exchange, and dissolution/fines migration.
In this paper, we have studied low salinity waterflood by systematic changing the rock wettability. The wettability is changed by varying aging with crude oil at elevated temperature. We are investigating how aging time effect affects core analysis properties like; spontaneous imbibition, Amott-Harvey and USBM wettability oil and water indices. The wetting properties were also cross-checked by NMR.
The detailed core analysis is the background for study of oil recovery by seawater injection and subsequent lowering of salinity. In addition to detecting trends of initial wetting and the potential for low salinity, all mechanisms for low salinity recovery are discussed. It is expected from the literature that the clay content in Berea cores favors oil recovery by low salinity waterflooding, however the more oil wet character of the Bentheimer cores in this study, seems more important for improved oil recovery by low salinity waterflood.