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Emulsions are always a drain on the operating budget. It is almost impossible to eliminate emulsions during crude production; however, emulsion problems can be reduced and optimized by following good operating practices. The following points should be included in operating practices. Chemical-Demulsifier Development Based on Critical-Electric-Field Measurements. Husveg, T., Bilstad, T., Guinee, P.G.A. et al. 2009 A Cyclone based Low Shear Valve for Enhanced Oil-Water Separation. Paper presented at the Offshore Technology Conference, Houston, Texas, USA, 4-7 May.
Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.
Abstract Activating naturally occurring nanoparticles in the reservoir (clays) to generate Pickering emulsions results in low-cost heavy oil recovery. In this study, we test the stability of emulsions generated using different types of clays and perform a parametric analysis on salinity, pH, water to oil ratio (WOR), and particle concentration; additionally, we report on a formulation of injected water used to activate the clays found in sandstones to improve oil recovery. First, oil-in-water (O/W) emulsions generated by different clay particles (bentonite and kaolinite) were prepared for both bottle tests and zeta potential measurements, then the stability of dispersion was measured under various conditions (pH and salinity). Heavy crude oils (50 to 170,000 cP) were used for all experiments. The application conditions for these clay types on emulsion generation and stability were examined. Second, sandpacks with known amounts of clays were saturated with heavy-oil samples. Aqueous solutions with various salinity and pH were injected into the oil-saturated sandpack with a pump. The recoveries were monitored while analyzing the produced samples; a systematic comparison of emulsions formed under various conditions (e.g., salinity, pH, WOR, clay type) was presented. Third, glass bead micromodels with known amounts of clays were also prepared to visualize the in-situ behavior of clay particles under various salinity conditions. The transparent mineral oil instead of opaque heavy oil was used in these micromodel tests for better visualization results. Recommendations were made for the most suitable strategies to enhance heavy oil recovery with and without the presence of clay in the porous medium; moreover, conditions and optimal formulations for said recommendations were presented. The bottle tests showed that 3% bentonite can stabilize O/W emulsions under a high WOR (9:1) condition. The addition of 0.04% of NaOH (pH=12) further improved the emulsion stability against salinity. This improvement is because of the activation of natural surfactant in the heavy oil by the added alkali—as confirmed by the minimum interfacial tension (0.17 mN/M) between the oil and 0.04% of the NaOH solution. The sandpack flood experiments showed an improved sweep efficiency caused by the swelling of bentonite when injecting low salinity fluid (e.g., DIW). The micromodel tests showed a wettability change to be more oil-wet under high salinity conditions, and the swelling of bentonite would divert incoming water flow to other unswept areas thus improving sweep efficiency. This paper presents new ideas and recommendations for further research as well as practical applications to generate stable emulsions for improved waterflooding as a cost-effective approach. It was shown that select clays in the reservoir can be activated to act as nanoparticles, but making them generate stable (Pickering) emulsions in-situ to improve heavy-oil recovery requires further consideration.
Chang, Hongli (University of Alaska Fairbanks) | Saravanan, Naresh (University of Alaska Fairbanks) | Cheng, Yaoze (University of Alaska Fairbanks) | Zhang, Yin (University of Alaska Fairbanks) | Dandekar, Abhijit (University of Alaska Fairbanks) | Patil, Shirish (King Fahd University of Petroleum and Minerals)
Abstract The formation of stable heavy oil emulsion, which may upset separation facilities and eventually lead to production impairment, is one of the most common issues encountered in the development of heavy oil reservoirs. This paper investigates the influence of various physicochemical parameters, including water cut, polymer status (sheared/unsheared), polymer concentration, demulsifier type and concentration, and the coexistence of polymer and demulsifiers on the stability of heavy oil emulsion. The viscosity of heavy oil emulsion is also studied at various water cut and polymer concentration. In this study, water-in-heavy oil emulsion was prepared at the water cut of 30% as the blank sample using heavy oil with API gravity of 14.5° and the synthetic brine. The effect of the water cut was investigated by both the bottle test method and multiple light scattering (MLS) method to validate the effectiveness and reliability of the MLS method. The other parameters were studied only through the MLS method. The results showed that the increasing water cut resulted in the decrease of heavy oil emulsion stability and could potentially invert the stable w/o emulsion to loose o/w emulsion at the phase inversion point where the emulsion viscosity peak occurred. Adding polymer, regardless of the polymer status, tended to reduce the stability of heavy oil emulsion, and the unsheared polymer contributed to less emulsion stability. However, the influence of polymer concentration was rather complicated. The emulsion stability decreased as polymer concentration increased, and further increasing polymer concentration enhanced the emulsion stability. A similar trend was also evidenced by emulsion viscosity with increasing polymer concentration. The addition of three oil-soluble emulsion breakers was able to break the heavy oil emulsion efficiently, whereas the water-soluble demulsifier had little demulsification effect. Furthermore, there existed an optimal concentration for the selected oil-soluble demulsifier to achieve the maximum separation. Although polymer itself could intensify the destabilization of heavy oil emulsion, it hindered the destabilization process of the heavy oil emulsion when the oil-soluble demulsifiers were added. This study will provide a comprehensive understanding of the factors affecting heavy oil emulsion stability.
Zhong, Hanyi (China University of Petroleum, East China) | Kong, Xiangzheng (China University of Petroleum, East China) | Qiu, Zhengsong (China University of Petroleum, East China) | Huang, Weian (China University of Petroleum, East China) | Zhang, Xianbin (Tianjin Key Laboratory of Complex Conditions Drilling Fluid) | Zhao, Chong (Tianjin Key Laboratory of Complex Conditions Drilling Fluid)
Abstract Owing to superior temperature stability in comparison with water-based drilling fluids, oil or synthetic-based drilling fluids are generally preferred for high temperature and high pressure (HTHP) formations. However, the thermal degradation of emulsifiers and polymeric components under HTHP conditions that results in loss of rheological and filtration control, barite sag or even fluid phase separation also occurs. It is a challenge to sustain these properties stable under such harsh condition. Since nanoparticles have potential to provide better thermal stability, improved filtration loss as well as emulsion stability, the aim of this study is to investigate the effect of nano carbon spheres on the properties of oil-based drilling fluids under high temperature conditions. The nano carbon spheres were synthesized with the hydrothermal reaction of glucose. The influence of nano carbon spheres on the rheological, filtration, emulsion stability, settlement stability, as well as lubricity of a typical mineral oil-based drilling fluid with oil to water ratio of 80:20 was investigated before and after thermal aging at 180 and 200°C, respectively. The structure characterization showed that the uniform hard nano carbon spheres exhibited intermediate wettability. Laboratory performance test indicated that, for the oil-based drilling fluid, the addition of nano carbon spheres improved the rheological properties in terms of yield point and the ratio of yield point to plastic viscosity, which is beneficial for transporting of drilling cuttings. After thermal aging at 200 °C, the filtration loss volume was reduced as high as 70%, and desirable filter cake quality was obtained by incorporation of 1.0 wt% spheres, meanwhile the electrical stability was improved both before and after thermal aging. Furthermore, the fluid formulated with the nano carbon spheres generated better barite sag control. The polarizing microscope observation showed that the nano carbon spheres accumulated at the water-oil interface and formed a steric barrier which probably explained the reason of the above enhanced performance. The green synthetic routes and environmental friendly characteristics of the nano carbon spheres, in combination with the excellent properties suggested that the nano carbon spheres hold potential as multi-functional additives for formulating oil-based drilling fluids for HTHP drilling operations.
Zhu, Youyi (Research Institute of Petroleum Exploration & Development, CNPC) | Yu, Peng (University of Science and Technology Beijing) | Fan, Jian (Research Institute of Petroleum Exploration & Development, CNPC)
Abstract Chemical flooding is one of enhanced oil recovery (EOR) methods. The primary mechanism of EOR of chemical flooding is interfacial tension reduction, mobility ratio improvement and wettability changes. Recent studies showed that enhancing emulsification performance was beneficial to improve oil displacement efficiency. The formation of Pickering emulsion by nanoparticles could greatly improve the emulsifying performance. Using nanoparticles stabilized emulsions for chemical EOR application is a novel method. In this study, six different types of nanoparticles were selected, including hydrophilic nano silica, modified nano silica, carbon nanotubes and bentonite, etc. The nanoparticle combine with petroleum sulfonate could form a stable emulsion. Particle wettability were measured by using contact angle measurement (OCA20). Emulsifying intensity index was measured for different nanoparticle-stabilized emulsions. The mechanisms of nanoparticle-stabilized emulsions and relationship between emulsion stability have been investigated. The influence of dispersant on nanoparticle-stabilized emulsions also has been investigated. Nanoparticles mainly play a role in improving the stability of emulsions while surfactant play a major role in enhancing the emulsifying dispersion. The wettability of solid particles was one of the most important factors that affects the stability of emulsions. Partial hydrophobic nanoparticles were much easier to form stable emulsions than hydrophilic nanoparticles. Nanoparticles could form a three-dimensional network structure, thereby the stability of the emulsion was improved. Use of surfactant to disperse nanoparticles could further improve the emulsion stability. Finally, three nanoparticles stabilized emulsion formulations were developed for chemical flooding EOR. Nanoparticle-stabilized emulsions could improve oil displacement efficiency in chemical combination flooding. This research was used to optimize chemical combination flooding formulation and has a guidance function for application of nanoparticles in chemical flooding EOR.
Summary Injecting water with chemicals to generate emulsions in the reservoir is a promising method in the enhancement of heavy‐oil recovery because the formation of oil‐in‐water (O/W) emulsions significantly reduces oil viscosity. Nanoparticles (NPs) (Pickering emulsions) can be used for this purpose as a cost‐effective alternative to expensive surfactants; however, such Pickering emulsions need to be stable for successful applications. The objective of this study is to screen the effective emulsifier for O/W emulsions from a broad range of solid NPs and identify suitable Pickering emulsifying agents (e.g., adjusting pH or salt concentration) that can render emulsions stable at relevant conditions, and to investigate how a range of physical parameters, such as particle concentration, water/oil ratio (WOR), and temperature affect emulsion stability. Five NPs—including cellulose nanocrystals (CNCs), silica, alumina, magnetite, and zirconia—were tested on their capabilities of stabilizing O/W emulsions through glass vial screening tests under various pH and salinity conditions. The screening results showed that the CNC could become an effective emulsifier by either adjusting pH or salinity. In addition, zeta potential measurements were conducted to explain the observations. The stabilization mechanisms of CNCs were studied through an epifluorescent transmitted microscope showing that the formation of a dense particle layer around the oil droplets, as well as a network in the continuous phase, were the two main mechanisms accounting for the high stability of the emulsions stabilized by CNCs. The effects of particle concentrations on the emulsion stability were studied quantitatively by analyzing the droplet‐size distributions calculated by the open-source ImageJ software, with the results showing a sharp decrease in droplet size, followed by a smooth change as the particle concentration increased. For the WOR effect, phase inversion from O/W to water‐in‐oil (W/O) emulsions was observed when the oil content was more than 0.6. The thermal stability of emulsions was studied both macroscopically by glass bottle tests and microscopically through a microscope, both of which show that the CNC‐stabilized emulsions remained thermally stable up to 100°C. The rheological properties of both aqueous dispersions of CNCs and the corresponding O/W emulsions were also measured under various salinity conditions. The results showed that the salinity had a great impact on the viscosity of the CNC suspension and the typical shear‐thinning behavior of Pickering emulsions. This study provides an option to enhance emulsion stability without surfactants, which will reduce the costs and facilitate field applications of emulsion flooding in heavy‐oil recovery.
Bottle tests are the preferred method to test petroleum emulsion stability in the industry today. A new technique using nuclear magnetic resonance (NMR) is available to evaluate both stability and demulsification behavior of emulsions. The NMR scans the water fraction throughout the entire length of the emulsion sample. These rapid measurements are designed to dynamically probe the emulsion, capturing its separation as a digital image. This case study presents the ways NMR has helped predict the effects of future well line-up changes.
Costa Salmin, Davi (Colorado School of Mines) | Delgado-Linares, Jose G. (Colorado School of Mines) | Wu, David T. (Colorado School of Mines) | Zerpa, Luis E. (Colorado School of Mines) | Koh, Carolyn A. (Colorado School of Mines)
Summary Some crude oils contain naturally occurring surfactants that avoid hydrate agglomeration. Natural hydrate antiagglomeration has been linked to different crude oil fractions, including asphaltenes. Asphaltenes can promote the formation of stable water-in-oil (W/O) emulsions due to their amphiphilic properties. The surfactant-like behavior of asphaltenes is related to their aggregation state. Asphaltenes are strong emulsifying agents when in an aggregated state but weak emulsifying agents when either precipitated or well solubilized in the bulk oil phase. The asphaltene aggregation state may be artificially modified, changing its interfacial activity, by mixing crude oil with heptane–toluene mixtures. This work investigated the influence of the asphaltene aggregation state on gas hydrate agglomeration. Results show that the natural hydrate antiagglomerant properties of crude oils can be highly dependent on the artificially induced asphaltene aggregation state. For instance, if asphaltenes were induced to be solubilized into the bulk oil phase, the natural hydrate antiagglomerant behavior was diminished. However, when asphaltene aggregation was induced, gas hydrate agglomeration was avoided. These new findings could have significant implications for the implementation of novel hydrate management strategies that can reduce or eliminate the need for external interventions and hence minimize capital and operational expenditures by taking advantage of the intrinsic natural antiagglomerant properties of some crude oils.
Mohammed, Mohammedalmojtaba (University of Alberta) | Lin, Lixing (University of Alberta) | Istratescu, Georgeta (University of Alberta) | Babadagli, Tayfun (University of Alberta) | Bademchi Zadeh, Amin (Canadian Natural Resources Limited) | Anderson, Mark (Canadian Natural Resources Limited) | Patterson, Chris (Canadian Natural Resources Limited)
Abstract Heavy oil in reservoirs exists in the form of either water in heavy oil (w/ho) emulsions after primary production under water drive, or during secondary recovery methods such as water or steam injection. In many cases, the decision to apply any secondary or tertiary methods such as CO2 or CH4 injection depends on the understanding of the behavior of these gases in w/ho emulsions at reservoir conditions. Such an understanding can reduce the uncertainties in reservoir modeling by providing an adequate fluid model for reservoir simulation and history matching studies. In this paper, we focus on the interfacial properties, relative volume change, and PVT behavior of CO2 and CH4 in (w/ho) emulsions. We first generated the (w/ho) emulsion using steam at 150oC. Next, the stability of our emulsion was tested using different criteria such as phase separation, viscosity of the produced emulsion compared with that of the starting oil, and the size and number of water droplets in the continuous medium. The experiments were run using two types of heavy oils that are collected from two representative fields in eastern Alberta, type A oil (27,000 cP) and type B oil (4,351 cP). A sensitivity analysis was performed to determine the impact of different operational variables such as water content in the emulsion, water pH, and flow rate; additionally, the role of asphaltene and resin in emulsion stability was investigated. The influence of water content in the emulsion was found to be critical and thus subsequent IFT and relative volume measurements as well as PVT analyses were conducted using emulsions of different water contents with a vol.% range from 10-70. The results were compared with a dead oil (no water) case. Two types of gases typically used to improve recovery in Alberta were tested: CO2 and CH4. IFT and volume measurements indicate the existence of critical water content which dramatically changes the behavior of the system; generally, emulsions with water content below this critical value exhibit lower IFT than the original oil, and the IFT falls steadily as the water content increases. The trend is reversed when the water content exceeds the critical value and IFT starts increasing before it stabilizes. This process happens when the water content reaches a vol.% higher than 50; however, it remains below that of the original oil. Regarding volume ratio, there seems to be a clear relationship between pressure and volume ratio of the emulsion and CO2 system. Overall, volume ratio increases as pressure increases regardless of water content. In general, for experiments run with CO2, data suggests that water content affects the rate of expansion, but ultimately the final volume ratio remains the same. The results of this work are significant in that they indicate the phase behavior of w/ho emulsions, and that CO2 and CH4 can vary considerably depending on the composition of oil and water content in the system. IFT, relative volume, and PVT measurements provide key information needed to build an adequate fluid model to reduce the uncertainties in reservoir simulation and history matching.