Schmidt, Julia (Delft University of Technology) | Mirzaie Yegane, Mohsen (Delft University of Technology) | Dugonjic-Bilic, Fatima (TouGas Oilfield Solutions) | Gerlach, Benjamin (TouGas Oilfield Solutions) | Zitha, Pacelli (Delft University of Technology)
Synthetic high molecular weight polymers have been utilized for enhanced oil recovery applications. Improving their injectivity remains an important issue for field applications. Large entangled polymer chains can clog pore throats, leading to injectivity decline. We investigated an emulsion polymer system and have developed a series of processing techniques to condition an acrylamide-based copolymer inverse emulsion system at a salinity of 50,000 ppm
The un-conditioned polymer system and test conditions were chosen to clearly demonstrate the impact of processing techniques on the injectivity behavior. The polymer solution was sheared with two agitators, a disperser and Ultra-Turrax, at different intensities and with a pressure-driven flow into a thin capillary to reduce the size of the largest polymer chains and disentangle the polymer chains while maintaining its viscosifying power. The injectivity of such differently sheared solutions was evaluated by performing filtration tests using a 1-micron membrane and sand-pack flooding tests.
Our experiments have established a master curve showing viscosity and screen factor dependences on accumulated energy during pre-shearing, regardless of the mode of shearing. The un-sheared polymer solution had an unfavorable behavior in filtration test and sand-pack flooding experiment. After pre-shearing, the filtration behavior of polymer solution and the injectivity in sand-packs improved significantly. Polymer solutions sheared with a disperser at an energy input of 15 MJ/m3 improved the injectivity gradient (e.g. the ratio of the resistance factor over 30 pore volumes injected) from 3.7 to 1.6, while the viscosifying power was reduced by only 2%. To reach the same injectivity improvement with Ultra-Turrax, an energy input of 31 MJ/m3 were required, which reduced the viscosity by 11%. Shearing the solution using a capillary at an energy input of 50 MJ/m3, did not reduce the injectivity gradient while viscosity was reduced by 19%. This indicates that the injectivity performance is shear-origin dependent and the resulting polymer structure, when sheared through contractions, has a different alignment as compared to shearing with the agitators, the disperser and Ultra-Turrax.
The effects of adding iron oxide NPs on the rheological and filtration properties of aqueous bentonite suspensions have been studied by several researchers. This paper presents an investigation into the effect of catalytic nanoparticles on the efficiency of recovery from continuous steam injection. A number of ongoing industry research projects are developing nanoparticles that work at the reservoir level and for fluid treatment. Though they may be a few years away from finalization, these efforts highlight nanotechnology’s increasingly sophisticated and growing application scope. This work focuses on the laboratory techniques for developing, assessing, and analyzing innovative water-based drilling fluids containing iron oxide (Fe2O3) and silica (SiO2) nanoparticles.
When two engineers lost their jobs during the industry downturn, they used the misfortune as an opportunity to develop an innovative concept that aims to make it a lot easier to move subsea gas long distances. Approaches to integrated investigative testing and root cause identification are discussed to prevent solid emulsions from stabilizing to impair flowlines and other field infrastructure.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
Hou, Qingfeng (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Wu, Qi (Key Laboratory for Green Chemical Technology of Ministry of Education. Collaborative Innovation Center of Chemical Science and Engineering, School of Chemical Engineering and Technology, Tianjin University) | Xu, Yan (Key Laboratory for Green Chemical Technology of Ministry of Education. Collaborative Innovation Center of Chemical Science and Engineering, School of Chemical Engineering and Technology, Tianjin University) | Zheng, Xiaobo (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Zhao, Yujun (Key Laboratory for Green Chemical Technology of Ministry of Education. Collaborative Innovation Center of Chemical Science and Engineering, School of Chemical Engineering and Technology, Tianjin University) | Wang, Yuanyuan (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Guo, Donghong (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Xu, Xingguang (Energy Business Unit, CSIRO)
Switchable surfactants can be reversibly converted between surface active and inactive forms by induced triggers including pH, ozone, ultraviolet light, CO2, N2 and heat. Examples of the CO2 triggered switchable surfactants are guanidines, imidazoles and amidines. In a typical process using CO2 triggered switchable surfactants, an emulsion originating from two immiscible phases is stabilized when CO2 is introduced. Afterwards, the emulsion is flushed by N2 or air, resulting in the destabilization and phase separation. These distinctive properties of the switchable surfactants make them appealing chemicals in the transportation and recovery of the crude oil. N'-alkyl-N, N- dimethylacetamidine bicarbonates, as a CO2-triggered switchable surfactant, has been reported in stabilizing the light crude oil (
In this study, a novel surfactant for flowback aid application was developed based on an optimization of well-known non-ionic surfactants. The objective was to meet intrinsic surfactant properties, such as high cloud point (CP), low surface tension (ST), adequate contact angle (CA) and low critical micelle concentration (CMC). In addition to the essential physical-chemical properties, improvement in fluid recovery and emulsion compatibility were also targeted. The surfactants were optimized by tailoring the hydrophilic head through controlled introduction of ethylene oxide and propylene oxide into different hydrophobic chains.
Surface tension measurements were made with a Dataphysics Instruments model OCA-15. Contact angles were measured using the sessile-drop method. The CMC concentration and cloud point were also conducted for physical chemical characterization. For the fluid recovery evaluation, flowback solutions were poured through 150g of 60/150 mesh- dry porous media contained in a 7 cm-inner-diameter, 9.5- cm-long column. Emulsion compatibility tests were also carried out using different proportions of crude oil and brine.
This paper evaluates various flowback additives in hydraulic fracturing applications between linear and branched alkoxylated surfactants. High cloud point enables a wide range of temperature applications and an increase in EO content showed an increase in cloud point values, contrary to PO effect. Nevertheless, CMC measurements showed that for an optimum scenario, EO addition should not be high, because undesired increases in CMC values may occur, which will affect the final surfactant dosage needed. All flowback aids demonstrated low surface tension as expected (approximately below 32 mN/m), but each being different in terms of surface wettability (contact angle), which could not be correlated with surfactant structure. Fluid recovery and kinetics of emulsion breakage increased significantly with different alkoxylation adjustments. For the new flowback aid developed, the fluid recovery was improved when compared against standard surfactants. Additionally, significant improvement was also found during emulsion breakage evaluation in terms of superior kinetics, final breakage, and water quality. This work provided a better understanding of how EO/PO affects intrinsic surfactant properties and enabled to find a surfactant that offers several benefits in terms of fluid recovery and non-emulsification of crude oil and water.
Li, Wai (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Zhao, Xionghu (China University of Petroleum Beijing) | Jiang, Jiwei (China University of Petroleum Beijing) | Peng, Hui (Beijing Oilchemleader Science & Technology Development Co., Ltd.) | Zhang, Min (Shengli Oilfield Exploration and Development Research Institute) | He, Tao (GWDC Drilling Fluid Company, PETROCHINA) | Liu, Guannan (China University of Mining and Technology) | Shen, Peiyuan (The University of Western Australia)
Biodiesel-based drilling fluid (BBDF) draws considerable attention because biodiesel has excellent environmental acceptability and great potential to provide high drilling performance. There are some investigations reported about BBDF both in laboratory and in the field recently, demonstrating its feasibility. In contrast to traditional petrodiesel and mineral oil, biodiesel has some chemical activity which affects the reliability of BBDF in drilling environment. This paper details the principles and strategies for developing and selecting additives of BBDF. A variety of experimental results obtained by laboratory tests were presented to elucidate the importance of suitable additives for an eligible BBDF. Electrical stability test and centrifuge test were conducted to evaluate the effectiveness of emulsifier. A six-speed viscometer and a high-pressure-high-temperature (HPHT) rheometer were used to measure the parameters of BBDF to evaluate organophilic clays and rheological modifiers. Density test was performed to investigate the suspendability of the fluids. Hot rolling treatment was carried out to study the thermal tolerance of the fluids. The laboratory results and the literature showed that both lime content and calcium chloride concentration have significant effects on the stability and rheological parameters of BBDF. Even moderate amount of lime in BBDF will significantly decrease the stability of BBDF. The effect of calcium chloride concentration on BBDF varies according to the type of emulsifier. A compound emulsifier based on fatty alkanolamides and alkyl sulfonates exhibits reliable ability to prepare stable, thermal-tolerate invert biodiesel emulsion. It offers biodiesel emulsion reduced viscosity compared to those given by traditional Span/Tween emulsifier combinations. For another, commercial organophilic clays cannot give satisfactory rheological parameters because the viscosity-temperature profile of BBDF is often steeper than those of traditional oil based drilling fluids (OBDFs). Therefore, rheological modifier should be used to compensate the viscosity loss of BBDF under high-temperature conditions. A condensate of alkoxylated fatty amine and polycarboxylic acid showed good performance to provide a relatively flat rheological profile. Some empirical laws, principles and strategies are summarized for BBDF additive selection. One is that the combinations of non-ionic and anionic emulsifiers have better effectiveness for biodiesel. The other conclusion is that lime content must be strictly controlled. With the boom of the biodiesel industry, it is predicted BBDF will take a place in the family of drilling fluid. However, most previous works show that BBDF may be not satisfactory when the temperature is over 120 Celsius degrees. This work presents valuable experience for further improvement of this promising drilling fluid.
Abdelfatah, Elsayed (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Chen, Yining (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Berton, Paula (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Rogers, Robin D (525 Solutions, Inc.) | Bryant, Steven (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary)
Thermal and flotation processes are widely used to produce bitumen from oil sand in Alberta. However, bitumen contains many surface-active components that tend to form water-in-oil emulsion stabilized by fines and/or asphaltenes. Although several demulsifiers have been proposed in the literature to treat such emulsions, these chemicals are sometimes not effective. We propose ionic liquids whose composition has been designed to enable effective treatment of these emulsions.
Different ionic liquids were synthesized and tested for their efficiency in treating bitumen emulsion obtained from a field in Alberta. Ionic liquids tested are mixtures of organic bases with acids. Mixtures of ionic liquids and bitumen emulsion were prepared at several mass ratios. The two components were mixed under ambient conditions. After mixing, segregation of different components in the mixture was accelerated by centrifugation for rapid assessment of the degree of emulsion breaking. Optical microscopy, rheology, thermal gravimetric analysis, and viscosity measurements were used to assess the effect of ionic liquids on bitumen emulsions.
The first set of ionic liquids with cations of different alkyl chain lengths were able to separate the water from the emulsion. However, these ionic liquids tend to form a gel when mixed with water. The number and length of alkyl chains proved critical for avoiding gel formation. Ionic liquids with multiple long chains on the cation were immiscible with the separated water. These ionic liquids were very efficient in diluting and demulsifying bitumen emulsion. The emulsion droplet sizes increased upon addition of the ionic liquid. The ionic liquid mixes into the bitumen phase released from the emulsion, yielding a viscosity at ambient temperature close to the pipeline specifications.
This work demonstrates that ionic liquids can be tailored to break bitumen emulsions effectively without heat input. The process developed in this paper can replace current practice for the demulsification and dilution of bitumen emulsions, which requires the emulsion to be heated significantly. Hence the ionic liquid process reduces the heat requirements and hence greenhouse gas emissions.
Hou, Qingfeng (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Zheng, Xiaobo (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Guo, Donghong (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Zhu, Youyi (Key Laboratory of EOR, Research Institute of Petroleum Exploration and Development, CNPC) | Yang, Hui (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences) | Xu, Xingguang (Energy Business Unit, Commonwealth Scientific Industrial Research Organization) | Wang, Yuanyuan (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Chen, Gang (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences) | Hu, Guangxin (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences) | Wang, Jinben (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences)
Stimuli-responsive emulsions have attracted much attention in diverse fields. However, research on the rapid and effective demulsification based on pH-responsive emulsions has barely been reported, although they are viewed as promising canditates for oil-water separation processes after oil recovery. In the present work, we have successfully synthesized a series of pH-responsive emulsions on the basis of a novel polymer containing amphiphilic and protonated moieties. The properties of these pH-responsive emulsions including stability, morphology microscopy, Zeta potential, and interfacial tension have been extensively investigated. We observed that the prepared oil-in-water emulsion could stay stable for more than 24 h within the pH range of 8-10, while it lost 80-90% of the water in 10-20 min if the pH was adjusted to 2-4. The variation in emulsion stability can be attributed to the protonation of poly [2-(N, N-diethylamino) ethyl methacrylate] (PDEA) residues at low pH values. Accordingly the polymers intend to become more hydrophilic and depart from the oil-water interface, leading to an increased interfacial tension. Furthermore, it was found that the applied polymers aggregated at the oil-water interface and that the morphology of aggregations was strongly affected by the pH values. These proposed polymers enabled the formation of emulsion with a controllable response to the pH stimuli. This work is expected to shed light on the development of stimuli-responsive emulsions and may have significant implications in the fields of oil recovery, waste water treatment, and so forth. For example, due to the high w/o interface activity of surfactants such as heavy alkyl benzene sulfonate (HABS) and petroleum sulfonate, severe emulsion has also been found with the alkali-surfactant-polymer (ASP) produced fluid. Currently, rapid breaking of these emulsion fluid is still a big challenge.
Sokhanvarian, Khatere (Sasol Performance Chemicals) | Stanciu, Cornell (Sasol Performance Chemicals) | Fernandez, Jorge M. (Sasol Performance Chemicals) | Ibrahim, Ahmed (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University)
Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants.
This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively.
Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid.
This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.