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.
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.
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
Xiu, Zongming (Solvay USA) | Dufils, Pierre-Emmanuel (Solvay Novecare) | Zhou, Jia (Solvay USA) | Cadix, Arnaud (Solvay Novecare) | Hatchman, Kevan (Solvay Novecare) | Decoster, Thomas (Solvay USA) | Ferlin, Patrick (Solvay Novecare)
As waxy crude oil comes to the surface, it will cool down and causing the waxy fraction to gel. The gelled crude chokes the well, leading to restricted or blocked production and costly downtime for operators. One of the most common chemical solutions to address the wax deposit challenge is the addition of wax inhibitors or pour point depressants (PPDs) to the production stream. However, most of the PPD's used in the field are organic solvent-based polymers, which require large quantities of hazardous organic solvents such as xylene and toluene. To propose an improved solution, a water-based amphiphilic PPD polymer dispersion system, synthesized using controlled radical polymerization technology has recently been developed. This specifically designed block copolymer is synthesized with a hydrophilic polymeric head group and a hydrophobic tail. The macromolecular design was specifically optimized to control particle size to create unique and stable amphiphilic PPD dispersion. The viscosity of the PPD, at high activity of about 40%, is between 200 and 250 cps at room temperature with a milky color, and it remains stable to 200°C under 500psi. Also, the PPD dispersion itself has a pour point of −30°C, and it can be easily formulated to be pumpable under −40°C. For performance evaluation, the water-based PPD dispersion was tested using a standard cold-finger apparatus and a pour point tester on crude oils from various global regions. The results showed that this PPD dispersion not only significantly reduced crude oil wax deposition by nearly 70%, but it also reduced the pour point of the crude by typically 18°C. Overall, the current research performed on macromolecular architecture design shows that this block polymer technology allows polymer adjustment to meet application needs for various crude types, and to tackle this important flow assurance challenges.
Wang, Yefei (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum East China, Ministry of Education, P. R. China, School of Petroleum Engineering, China University of Petroleum East China) | Yang, Zhen (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum East China, Ministry of Education, P. R. China, School of Petroleum Engineering, China University of Petroleum East China) | Wang, Renzhuo (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum East China, Ministry of Education, P. R. China, School of Petroleum Engineering, China University of Petroleum East China) | Chen, Wuhua (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum East China, Ministry of Education, P. R. China, School of Petroleum Engineering, China University of Petroleum East China) | Ding, Mingchen (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum East China, Ministry of Education, P. R. China, School of Petroleum Engineering, China University of Petroleum East China) | Zhan, Fengtao (College of Science, China University of Petroleum East China) | Hou, Baofeng (School of Petroleum Engineering, Yangtze University)
A novel indolizine derivative inhibitor for acidization was introduced. It could exhibit effective corrosion inhibition at a much lower concentration without propargyl alcohol and shows economic and environmental advantages. From quinoline, benzyl chloride, and chloroacetic acid, two indolizine derivatives were prepared under certain conditions. These inhibitive indolizine derivatives were both synthesised from benzyl quinoline chloride (BQC), which one of the conventional quaternary ammonium corrosion inhibitors used for acidising. The target compound was purified and instrumental analysis methods including elemental analysis, high-resolution mass spectrometry (HRMS), and NMR were used to characterise the chemical structure. The inhibition performance of the indolizine derivatives in 15 wt.% HCl, 20 wt.% HCl, and mud acid (12%HCl + 3%HF) for N80 steel was investigated by weight loss measurement, electrochemical method (potentiodynamic polarization and EIS), and SEM surface morphology assessment.
When 0.1 wt.% indolizine derivative was added, the inhibition efficiency of N80 steel in 15 wt.% HCl at 90 °C increased to 98.8 % and 99.1 % respectively without the synergistic effect of propargyl alcohol: however, in terms of BQC, even at a dosage of 1.0 wt.%, the inhibition efficiency of N80 steel only reached 83.3 % under the same conditions. The novel derivative could impart an improved corrosion resistance effect. Compared with BQC, there are more active adsorption sites in the derivative and therefore the inhibitor could be better fastened to the steel surface. The firmly adsorbed inhibitors would thereby prevent the metal surface from making contact with H+ ions and finally increase the inhibitory effect. As a high-efficiency corrosion inhibitor, the novel indolizine derivatives may offer a new strategy for corrosion protection in acidising.
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.
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.
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.
Adsorption of surfactant onto rock surfaces is dependent upon a number of factors, including characteristics of both the adsorbent and surfactant molecules. Considering that surfactant-based unconventional means to improve oil recovery are strongly dependent on the interaction at the liquid/liquid interface between soluble surfactant solution and crude oil, loss of surfactant to liquid/solid interfaces can create a negative effect for some of these applications in terms of performance and economics.
This study; therefore, focuses on investigating the adsorption mechanism of surfactants onto sandstone and limestone reservoir media. Besides quantifying how much surfactant is adsorbed, emphasis specifically on the effect of surfactant parameters on the adsorption capacity was evaluated. Although literature well documents that mineralogy, temperature, pH, inclusion of other chemicals, and salinity all play strong roles on the adsorption capacity of surfactants on a solid surface; all of these parameters, with exception of mineralogy, were maintained as constants for this work.
Anionic alcohol propoxy sulfate, nonionic alcohol ethoxylate, and ether carboxylate surfactants were studied. Academic focus for this effort was placed on surfactant parameters being evaluated including the structure of the surfactant hydrophilic head group and the surfactant hydrophobic tail. The number of mechanisms involved in surfactant loss from aqueous solutions to assorted porous media adds to the complexity of this phenomenon. Experimental results show that various surfactant parameters affect the adsorption differently based on their interaction with different adsorbents. An increase in hydrophobicity appears to increase surfactant adsorption. This was observed through a number of different mechanisms including increasing percent of propylene oxide (PO) and increasing degree of hydrophobe branching of the surfactants. Conversely, increasing carbon chain length and keeping the percent of PO more constant appeared to show a general decrease in adsorption trend with alcohol propoxy sulfate and a discernible decrease in adsorption in sandstone versus limestone mineralogy. It was also observed that varying ratios of propylene oxide and ethylene oxide extensions to alcohol alkoxy sulfate molecules will have an influence on surfactant adsorption.
Surfactant properties provide information on the type and mechanism of interactions involving surfactant molecules at the solid/liquid interface and their efficiency as surface-active agents. The findings from this study can be used to improve understanding on how the role of different surfactant parameters may affect surfactant adsorption. This will help lead to enhancements in designing surfactant molecular structures that in turn minimize adsorption to rock surfaces, while maintaining desired fluid performance for effective oil recovery.