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.
In the fluid flow study of polymer solutions through porous media in chemical enhanced oil recovery (ChemEOR) it is important to take into account very important properties such as the adsorption of polymer on mineral substrates, the residual resistance factor (Rk), the resistance factor (Rm), the wettability of the medium and cumulative recovery factor. For these reasons, this study has as main objective to evaluate rock-fluid behavior in presence of polymeric formulations by coreflood tests in porous media representative of extra-heavy crude reservoir conditions. To do this, an experimental methodology was proposed and a range of concentrations (800, 1500 and 2000 ppm) was established as the main variable of this study. Subsequently, relative permeability curves (Kr) on real sand cores were generated with an average absolute permeability of 7486.60 mD. Resulting in endpoints of the area of interest of: 29.0% and 65.6% of Swirr (Irreducible water saturation) and Sor (Residual oil saturation) respectively and a primary recovery factor of 36.4%. The amount of polymer adsorbed under dynamic regime was 19.1, 124.1 and 136.9 ug polymer/g rock. Following the same order, the values of additional oil recovery factor under polymer injection were 5.4, 10.2 and 15.2%, indicating a proportional increase with respect to injected concentration. However, there was no apparent correlation between the polymer concentration and residual resistance factor. Additionally, the initial wettability of the medium was preferential to water and this property increased with the injection of polymer formulations. Finally, using a methodology developed in this study, recycled polymer produced efficient results in ChemEOR processes generating an additional recovery factor of 2.38%. It also reduced the mobility of water in 98% (of that reported initially) and lastly its injection proportion per volume of crude produced was 3.522.
Seright, Randall S. (New Mexico Institute of Mining and Technology) | Wang, Dongmei (University of North Dakota) | Lerner, Nolan (Cona Resources Limited) | Nguyen, Ahn (Cona Resources Limited) | Sabid, Jason (Cona Resources Limited) | Tochor, Ron (Cona Resources Limited)
This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada’s Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.
This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
This paper examines oil displacement as a function of polymer solution viscosity during laboratory studies in support of a polymer flood in the Cactus Lake reservoir in Canada. When displacing 1610-cp crude oil from field cores (at 27°C and 1 ft/d), oil recovery efficiency increased with polymer solution viscosity up to 25 cp (7.3 s-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of the paper explores why this result occurred. That is, was it due to the core, the oil, the saturation history, the relative permeability characteristics, emulsification, or simply the nature of the test? Floods in field cores examined relative permeability for different saturation histories—including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1000 cp. In nine field cores, relative permeability to water (
Physical adsorption and mechanical entrapment are two major causes of polymer retention in porous media. Physical adsorption is believed to be an equilibrium process and is often modelled by assuming a Langmuir isotherm. The outcome is steady-state pressure response because the permeability reduction is also accounted for by adsorption. However, some experimental data show gradual increase of pressure with time implying that polymer retention is a kinetically-controlled process.
In this paper, we discuss simultaneous effect of sorption and mechanical retention on the polymer retention in porous media. An exact solution for 1-D flow problem for the case of constant filtration coefficient and Langmuir sorption isotherm, including explicit formulae for breakthrough concentration and pressure drop across the core is derived. The general model with varying filtration coefficient was successfully matched with coreflood data confirming the occurrence of simultaneous sorption with deep bed filtration.
In the absence of mechanical entrapment, the physical adsorption causes delay in the polymer front and does not affect the polymer concentration behind the front. Addition of mechanical entrapment results in very slow recovery of the injected concentration at the outlet (for varying filtration coefficient) or reaching to a steady-state concentration, which is only a fraction of the injected concentration (for a constant filtration coefficient). The results indicate that the accurate assessment of polymer retention requires both pressure and effluent concentration data at the outlet of the porous medium. In many cases, the kinetics involved in the mechanical entrapment could be very slow. In such cases, the experiments with few pore-volumes of injected polymer can be misleading and should not be directly used for field simulations.
Significant injectivity loss during polymer injection measured particularly in the near wellbore has been reported. This challengeable issue is identified as bridging polymer adsorption caused by the bridging of pore throats via macromolecular polymers previously stretched under elongational flow conditions occurring in the vicinity of the injection well. There has been no attempt to describe this phenomenon by numerical simulation model because the conventional Langmuir isotherm widely used in reservoir simulation is not able to contain this bridging-adsorption observed in complicated polymer flooding experiments.
This study focuses on the development of numerical model for the bridging adsorption by implementing population balance theory and performs extensive simulation verifications with small core-scale reservoir rock. To reflect distinct flow condition to induce bridging adsorption, the rate of bridging adsorption is established by considering the relationship of expanded polymer under shear force and narrow pore size. To verify the feasibility of new model, simulation results are compared with experiment output reported in previous studies. The simulation results indicate that a considerable amount of bridged polymer can be generated in the low permeability cells only if the polymer solution is exposed to high shear velocity related with shear rate. This is in accordance with a number of previous experimental reports. In addition, the mechanism to induce permeability reduction is totally different from that of conventional Langmuir's isotherm which is widely incorporated in commercial simulators. With buildup of bridging-polymer, the adsorption model can enable the application of numerical simulation targeted at chemical EOR process to be wider.
Polymer retention is challenging issue in transport of polymer through porous media. Previous studies have not researched retention considering pore size related to permeability substantially. The retention is of importance with respect to not only polymer loss but also permeability reduction. For this reason, accurate representation of polymer retention affected by pore size is necessary. This study proposes a new method to correlate permeability reduction with pore radius. The proposed method improves estimation of permeability reduction for both low and high permeability cores. In addition, polymer flood is assessed with estimated permeability reduction by proposed method in field-scale model.
In western Canada, there are significant amounts of oil sands reserves that have little or no cap rock with a top water zone (Alturiki et al 2011); because of huge heat loss, conventional SAGD process is uneconomical when it is directly applied in this type of reserves.
In this study, it is proposed that high temperature polymer can be injected into the bottom of the top water zone to establish a stable high viscosity layer in order to prevent steam from leaking to the top water zone. Lab tests were first conducted to screen the polymers. In order to select a proper polymer which was able to have stable viscosity under high temperature, viscosities of different polymers at different temperatures were measured; and concentration of the selected polymer was optimized. Then numerical simulations were performed to evaluate the feasibility of using the selected polymer to improve SAGD performance in oil sands with top water. The numerical simulation model was based on Athabasca oil sands reservoir. In this formation, the top water zone was around 94 meters, while the reservoir thickness was about 30 meters. The vertical permeability was 50 mD and 1,400 mD for the top water zone and the oil zone, respectively. And the porosity was 10% for the top water zone and 30% for the oil zone. The effect of the polymer injection strategy including the polymer injection parameters, such as polymer slug size, injection rate, injection time and well distance on the performance of SAGD process was studied.
The numerical simulation results suggested that, polymer injection was able to block the heat from leaking to the top water zone. With polymer injection, the cSOR can be reduced from 8.5 m3/m3 to 4.8 m3/m3, while for the case without top water, the cSOR was 3.8 m3/m3. This indicates that polymer injection is technically feasible to improve SAGD performance in oil sands with top water.