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 (
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.
Inflow Control Devices (ICDs) are being increasingly used in complex, heterogeneous reservoirs to make the inflow profile more uniform, delay breakthrough of water and/or gas and limit differential depletion, which can lead to crossflow and other detrimental phenomena. However, ICDs not only alter inflow behaviour: they also affect outflow of fluid during chemical treatments, such as scale squeezes, stimulation,
Methods to account for the additional flow resistance from ICDs when predicting placement of bullheaded treatments are discussed in this paper, in particular, to evaluate whether a theoretical approach based upon Bernoulli's Theorem leads to sufficiently accurate predictions in the absence of laboratory correlations between pressure drop across the ICD and flow rate. This approach may also become significant where the laboratory calibration might be expected to have changed during well life, such as, under the influence of erosion.
The paper describes two analytical methods of simulating placement in a multi-zone well in a heterogeneous reservoir in the Middle East: the first is empirical and models the pressure drop using an equation derived from calibration data in the laboratory; the second uses the Bernoulli equation, and is theoretical. For the empirical approach, the laboratory-based pressure-drop/flowrate calibration data were fitted to an equation, with parameters that depended upon the nozzle dimensions. The theoretical approach calculated the pressure drop using the Bernoulli equation for a cylindrical ICD nozzle. Both methods were used to simulate placement of a generic scale-inhibitor squeeze treatment and the corresponding chemical returns for each zone in the well. In general, the differences in the predictions between the two models were found to be very minor, showing that a theoretical approach is sufficiently accurate to design and evaluate chemical treatments in wells fitted with ICDs in most cases.
This means a very rapid analytical approach can be used to design and evaluate near-wellbore treatments in such wells without resorting to much more complex, numerical-based reservoir simulators, even when calibration data about the ICD performance are not available.
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.
A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability.
The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde.
Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face.
In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium.
This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).
Process upsets in high oil production facilities can hinder optimal plant performance and result in system shut-ins. Based on several successful demulsifier chemical trials, scientists and engineers have developed a guideline on how to optimize production throughout the chemical trial period. Factors such as chemical injection rate, export crude oil monitoring (basic sediment and water (BS&W) and salt), discharge water quality(from the water-oil separator (WOSEP)), and transformer voltage fluctuation (dehydrator and desalter) plays an important role in minimizing the system upset.
Prior to chemical trial, scientists and engineers analyze the process system to understand individual vessel functions and limitations. Incumbent chemical program provides baselines and key performance indicators (KPIs) set minimum oil specifications before exporting oil to refineries. Demulsifier injection rates are reduced based on the chemical program optimization proposal until it reaches the dosage limit while maintaining stable process throughout the trial. Therefore, scientists and engineers may evaluate the demulsifier’s performance based on the KPIs set with no system upset. Fast fluid separation in the High Pressure Production Traps (HPPTs) is an important strategy in order to improve process system’s performance.
High volume oil production systems typically have two HPPTs in parallel for initial water separation. Downstream of the HPPTs is the Low Pressure Production Trap (LPPT), which is mainly used for gas separation. Oil continues to the dehydrator to finish the dehydration to meet the pipeline BS&W requirement. The dehydrator is where the transformer is located for the electrostatic grid and high amounts of water separation can cause fluid levels to fluctuate and trip the transformers.
Throughout several field trial experiences, demulsifier rates can be optimized (reduced) further when it shows increased water separation at HPPT vessels. Clear water from HPPTs discharge, valves in water leg HPPTs open more (%), stable voltage grid (dehydrator/desalter), and less than 0.2% BS&W with less than 10ptb salt recorded at the export oil gives a good indication that the process is stable. Thus reduced the risk for system upset.
This paper summaries the best approach to optimize chemical rates in high volume oil production systems, analyzes qualitative and quantitative system checks to verify stable operations, and discusses potential risks involved when reaching lower limits of effective chemical rates.
This paper discusses an optimum approach to design and execution of a robust chemical enhanced oil recovery (EOR) surveillance program considering the physics and uncertainties involved during the implementation of a chemical EOR (CEOR) application at reservoir scale. The surveillance includes techniques, measuring points, and frequency of data acquisition.
Based on field experience, a robust surveillance plan plays a key role in ensuring high performance of a CEOR application during implementation and execution at reservoir conditions. A proper surveillance program should focus on acquiring information associated with the main uncertainties related to fluid-fluid and rock-fluid interactions, the impact of reservoir heterogeneities at reservoir scale, fluid dynamics, and the composition and stability of the chemical formulation. The acquired information should be given to the CEOR modeling team to follow up, interpret, and adjust the CEOR process and reservoir model. Also, the information should be given to the reservoir operation team to tune up the CEOR injection and production process to help optimize performance.
Typically, specialized literature focuses on describing CEOR formulation design and evaluation; laboratory requirements, experimental settings, and analysis results; field application design and implementation; and overall results of field applications. This work emphasizes CEOR process surveillance, its importance, and impact with respect to oilfield scale applications.
There are multiple uncertainties regarding the physical parameters and phenomena that control the performance of the CEOR at reservoir scale (e.g., are uncertainties associated with fluid saturation and properties, rock-fluid interactions, reservoir heterogeneities, and alkali-surfactant-polymer (ASP) formulation behavior at reservoir conditions). A proper surveillance design and implementation help mitigate the impact of the mentioned uncertainties.
Therefore, surveillance is paramount for the success of a CEOR application. The design and execution of a robust surveillance program should consider the main uncertainties associated with the CEOR formulation operating window, fluid-fluid and rock-fluid interactions, reservoir heterogeneities, reservoir conditions, injection-production environment, and various time scales for the timely use of the acquired information and the interpretation feedback to the CEOR modeling and operation teams.
This work discusses the physics and uncertainties considered during the design and execution of an optimized surveillance program. A systematic approach is provided considering fluid-fluid and rock-fluid interactions, reservoir heterogeneities, CEOR formulation operating window, injection – production environment, and time scales to feedback the acquired and interpreted information during the surveillance program execution.
Abubakar Umar, Abubakar (Centre of Research in Enhanced Oil Recovery, Universiti Teknologi PETRONAS) | Mohd Saaid, Ismail (Centre of Research in Enhanced Oil Recovery, Universiti Teknologi PETRONAS) | Adebayo Sulaimon, Aliyu (Department of Petroleum Engineering, Universiti Teknologi PETRONAS) | Mohd Pilus, Rashidah (Department of Petroleum Engineering, Universiti Teknologi PETRONAS) | Amer, Nurul Asna (Centralized Analytical Laboratory, Universiti Teknologi PETRONAS) | Halilu, Ahmed (Department of Chemical Engineering, Universiti Malaya.) | Mamo Negash, Berihun (Department of Petroleum Engineering, Universiti Teknologi PETRONAS)
Water-in-oil petroleum emulsions were prepared using response surface methodology (RSM) based on box-Behnken design (BBD). The emulsions were prepared using a treated Malaysian offshore crude oil, where the saturates, aromatics, resins and asphaltenes (SARA) of the crude oil were extracted using a modified SARA analysis. Other native solids, wax and asphaltenes extracted from oilfield emulsions and other crude oils were used as the emulsifying agents. In this paper, we focus on the characterization of some oilfield solids extracted from Malaysian offshore fields and further investigated their potentials to stabilize petroleum emulsions. The effects of the solids alone, and in combination with asphaltene/resin and wax were studied using statistical methods and the stabilities of the emulsions examined using a Turbiscan optical analyzer. The main advantage of Turbiscan is to obtain a faster and more accurate detection of destabilization phenomena in non-diluted emulsion than can be detected by the naked-eye (observation), especially for an opaque and concentrated dispersion system. The sample characterizations were conducted with FTIR, TGA, FESEM/EDX, XRF and XRD. Results showed that the major native solids present in the samples were paraffins and calcium carbonate. Further analysis revealed that the solids by themselves do not significantly contribute to emulsion stability. However, in the presence of asphaltene/resin compounds, the prominent solids such as paraffins and calcium carbonate enhance the stability of the emulsion irrespective of asphaltene/resin concentrations.
Innovation in the analysis of oil well surface measurements has led to the discovery of an instantaneous and straightforward emulsion detection calculation. When applied in the Bahrain Field, this led to the treatment of emulsion in over 100 wells, resulting in a cumulative production gain of over 500,000 barrels to date at negligible cost. Artificial Intelligence (AI) was then employed to identify and understand factors related to emulsion and optimisation treatment programs. Once the wells were treated and the method was confirmed to prove emulsion existence, a focused approach was carried out to understand it further. Wells were categorised based on their production response to standard demulsifier bullheading.
In addition to a variety of well parameters, this data was used to build a machine learning model that helped identify patterns with regards to problematic zones, properties of wells with emulsion, and the best treatment method for each well. The results of the study were rather substantial and resulted in numerous new insights. Firstly, a model was built to predict the sustainability and economics of expected bullheading job treatments. This is currently being used to rank the priority of wells for either bullheading treatment or continuous chemical injection. Once the wells were classified into basic sub groups and sorted by zones, geographic analysis was carried out to identify wells with emulsion being formed as a result of waterflooding. This led to further insight into the nature of emulsion blocks, where in some cases, although it was found that these blocks exist downhole, traces of emulsion will flow to the surface and can have a unique signature.
This paper discusses in further detail insights into emulsion and the different types of AI algorithms used to answer questions raised as a result of the discovery. The necessity of using machine learning cannot be overstated enough and the observations made in the paper could not have been found if it were purely by observed by the naked eye.
The topic of emulsion is highly understudied, and the concept of using the emulsion detection calculation was not published before. In addition to highlighting this discovery, this paper can influence other operators to test their findings and have a real world application of machine learning in their fields.