The objectives of the present study are to evaluate a zwitterionic surfactant for applicability in EOR. The surfactant was tested in terms of its salt tolerance, thermal stability, interfacial reduction capability, wettability alteration and resistance to adsorption. The effect of salinity and alkalinity was also tested on the above stated physico-chemical properties of the surfactant.
The salt tolerance of the surfactant was tested by testing for precipitation of surfactant solution with increasing salinity at 30 °C and 80 °C. The thermal stability of the surfactant was tested by TGA testing. The interfacial tension of the crude oil and surfactant solution with varying surfactant concentration, salinity and alkalinity was tested by spinning drop technique. The wettability alteration by surfactant solution was tested by measuring contact angle on an oil wet sample. The adsorption study was done by measuring the concentration of surfactant after its solution was exposed to adsorption on crushed rock sample.
The surfactant had salt tolerance of 20% salinity. The surfactant was found stable to 130 °C as per TGA curve. The interfacial tension (IFT) was reduced to ultralow value by surfactant solution for concentration at and above its critical micelle concentration. The presence of salt had minimal effect on the IFT reduction capability of the surfactant solution. Presence of alkali had synergetic effect on IFT reduction. The wettability of the oil wet sample was altered to preferentially water wet by surfactant. The loss of surfactant due to adsorption was found to be within recommenced range for applicability in EOR. These excellent physico-chemical properties of the zwitterionic surfactant suggest that it can be used in the mature oil fields for recovery of trapped oil.
Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.
One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.
It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.
This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
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.
A new method has been developed to differentiate and quantify the amount of primary amines through a simple chemical process. Colored cyclic adduct compounds are formed by reaction of selective chemicals with primary amine. This adduct formation is preferential to the primary amine, even in the presence of a mixture of secondary and tertiary amines. The adduct shows selective enhanced fluorescence emission at 475-nm wavelength under specific excitation with 420 nm. Due to enhanced fluorescence activity, quantification becomes possible, even below a 1-ppm concentration of specific primary amine. A chemical matrix, formulated with the mixture of different concentrations of primary, secondary and tertiary amines, helps to differentiate and quantify primary amines present in the mixture, even at lower concentrations. This method is validated under synthetic field brine conditions to detect and quantify primary amines towards field applications.
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.
Jie, Zhang (CNPC Engineering technology R&D company limited) | Xu, Xianguang (CNPC Engineering technology R&D company limited) | Wang, Lihui (CNPC Engineering technology R&D company limited) | Li, long (CNPC Engineering technology R&D company limited) | Zhang, Die (CNPC Engineering technology R&D company limited) | Zhao, Zhiliang (CNPC Engineering technology R&D company limited) | Wang, Shuangwei (CNPC Engineering technology R&D company limited)
Severe formation damage is induced by the invasion of working fluid and the subsequent water blocking. Surface modification by surfactant adsorption can change the wettability of the rock surface to enhance the removal efficiency of reservoir fluid and reduce the water blockage damage. Therefore, surfactant shows a good potential applicant in condense reservoir. In the current paper, an oligomeric silicone surfactant (OSSF) containing sulfonic acid groups is synthesized to improve the water flowback effect.
The critical micelle concentration (CMC) is determined by equilibrium surface tension. Micelle can be formed above the CMC and its size and distribution increase with the concentration. At the same time, the surface tension increases with the aging temperature but decreases with the adding of inorganic salt. The OSSF adsorption through solid-liquid surface can change the surface chemical composition and transfer the wettability of reservoir from water-wet to gas-wet by decreasing the surface energy. Increasing temperature leads to the change in the adsorption isotherm from Langmuir type (L-type) to "double plateau" type (LS- type). Quantum chemistry study shows that the adsorbed layer of OSSF can reduce the adhesive force of CH4 and H2O on the pore surface of cores. The OSSF can also decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).
It is found that the surface tension of OSSF increases with aging temperature but decreases with the adding of inorganic salts.The OSSF has positive effect on wettability reversal to water-wet reservoir by adsorption on solid-liquid interface. The results indicate OSSF adsorption layer can change surface chemical composition and exhibit lower interface energy than that of the cores. The presence of NaCl can decrease foaming volume and improve foam stability of OSSF. At the same time, OSSF can decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).
Formation of scales in near-wellbore reservoir/downhole and production systems can lead to production loss, system integrity and reliability degradation, and fouling of device and equipment. The mitigation and remediation of oilfield depositions can be difficult and costly. Better understanding of the key factors impacting scale dissolution, such as temperature and pH will benefit scale mitigation practices. Most of the research and investigation of silicate dissolution for example are based on low temperature experiences (e.g., <100 °C). Strong acids such as concentrated HCl, HF and aqua regia may not be applicable for field application.
In this study, field depositions with various scale types such as silicates, carbonate, sulfides are characterized and used for studying effects of pH, temperature and solvent on their dissolution. Experiments with oilfield scale deposit samples including silicates were conducted with high temperature thermal aging cells at temperature range >100 °C and pH from 6 – 8. Dissolution test with field scale samples were also conducted under ambient conditions. Various solvents including xylene, HCl and acetic acid were used in the test.
To summarize the results, decreasing temperature has limited effect on dissolution of magnesium silicates, but improves dissolution of calcite and anhydrite which coexist with the field sample. Decreasing pH improves the dissolution of magnesium silicate and calcite. Total amount of dissolved silicates can increase significantly due to appropriate pH decrease. Solution pH is increased dramatically due to the formation of hydroxyl ions during the dissolution process. The reaction for dissolution of metal silicate scale is proposed based on observation and results in the study. More fine particles are produced after dissolution and suspended in solution for at least 15 minutes, which makes solid mitigation possible by applying proper agitation. Oilfield deposits can include a variety of components, and appropriate scale sample characterization should be utilized for selection of mitigation/remediation approaches.
This paper provides novel information of oilfield scale dissolution (including silicate scale) at high temperature by using field applicable treatment approaches. Results lead to better understanding of silicate dissolution at various pHs and temperatures, and required conditions for successful mitigation and remediation of oilfield scale deposits
Cai, Hongyan (SKL-EOR, RIPED, CNPC) | Wang, Qiang (SKL-EOR, RIPED, CNPC) | Luo, Wenli (SKL-EOR, RIPED, CNPC) | Wang, Hongzhuang (SKL-EOR, RIPED, CNPC) | Zhou, Xinyu (SKL-EOR, RIPED, CNPC) | Li, Jianguo (SKL-EOR, RIPED, CNPC) | Zheng, Yancheng (Yangtze River University)
In recent decade, various betaine surfactants have been developed and extensively investigated for binary Surfactant-Polymer flooding (SP flooding) due to their high interfacial activity at oil-water interface, excellent thermal tolerant and salt/divalent ion resistant characteristics under harsh reservoir conditions. Herein, a new type of guerbet alkoxy betaine surfactant (GAB) was prepared and evaluated for SP flooding. In order to boost the emulsification capability of betaine surfactant, ethylene oxide (EO) functional group was incorporated into betaine molecule and guerbet alcohol was selected as hydrophobic group. Firstly, glycidyl ether was prepared by reaction of alkoxylated Guerbet alcohol and epoxy chloropropane. Then, glycidyl ether and dimethyl amine generated tertiary amine. In the last step, surfactant GAB was synthesized by quarternization reaction of tertiary amine with 3-chloro-2-hydroxyl propanesulfonic acid sodium salt. In-lab performance evaluations, including interfacial tension, long term stability, contact angle, and phase behavior were conducted for this GAB surfactant. The developed surfactant demonstrated very good compatibility with high temperature, high salinity (HTHS) reservoir conditions. Applicability range of GAB surfactant amounted to 275,000 mg/L and 120 °C. Ultralow interfacial tension with crude oil was obtained using diluted GAB solutions with weight concentration ranging from 0.03% to 0.20%. For formulation composed by 0.5% GAB and 0.5% amidobetaine, Winsor III middle phase microemulsion was formed with dehydrated light oil from a high temperature, high salinity carbonate reservoir. The solubilization ratio mounted to 16 at reservoir temperature of 95 °C and optimal salinity of 50,000 mg/L. Compared with guerbet alkoxy sulfate surfactant and conventional sulfobetaine with similar structure, the developed betaine surfactant GAB showed better thermal stability, higher interfacial activity, and intensified emulsification capability under HTHS conditions.
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.