bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Chemistry Issues and Solutions Associated with Chemical EOR
Authors: Graham Gordon M. , Frigo Dario M. 
Published: March 2019

Abstract
Chemical EOR is an increasingly employed approach used to enhance oil recovery by combining changes in fluids mobility, macroscopic sweep, interfacial tension, etc. to essentially improve, or extend the economic life of a water flood. It includes flooding with polymer, surfactant, alkaline/surfactant, alkaline-surfactant-polymer (ASP), CO2 and / or other miscible gases which is often combined with waterflood (e.g., CO2 WAG) etc. However, the improved oil recovery is often accompanied by physical and chemical changes in the produced fluids that cause many production-chemistry (PC)-related challenges when fluids subsequently arrive in the production system, including exacerbation of scale and naphthenates deposition, carboxylate deposits associated with injected polymer, enhanced corrosion and separation issues, etc. Understanding and predicting the production chemistry challenges at producers are further complicated by chemical changes as the fluids propagate through the reservoir such as reaction with reservoir formation minerals, chemical retention, chemical degradation and hydrolysis, etc. More importantly the implications for the production system and processing facilities are not always accounted for and proactively managed.
The paper evaluates the main chemical changes that occur in the system for each EOR approach –– and shows how these changes, including in situ reservoir reactions and the stability/instability of the EOR packages themselves can exacerbate a range of PC-related challenges especially when considering the likely production of up to three different fluids: formation water, the EOR flood medium and any previous flood water from previous secondary recovery
The paper includes modelling results, laboratory results to validate model predictions as well as examples from field case studies to illustrate the impact of the chemical changes referred to above. Specific highlights include the impact of the use of either high- or low-pH EOR fluids on scale control, corrosion control and asphaltenes control; for scale it examines both inhibitor performance per se as well as retention onto rock during squeeze treatment. Also illustrated are the risk of carboxylate-based deposit derived from polymer flood, and the phenomenon of carboxylate-based solids and soaps, which can exacerbate the separation of an already highly challenging system.
The overall conclusion is that chemical EOR can have significant impact on PC and that these should not just be considered at the design stage and not just for the injection system but also to take into account the impact these may have on production wells following breakthrough of flood waters, showing that essentially each new or exacerbated PC issues can be predicted or at least anticipated with the required degree of confidence before implementation of EOR.
Innovative Acidizing Solutions for Severely Damaged Clay-Rich Sandstone Reservoir with Gravel Pack Completions in Offshore Myanmar
Authors: Kim DongKyoon , Bae Youngwoo , Liu Hai 
Published: March 2019

Abstract
Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (&gt;100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval.
Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (∼0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically "welding" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration.
The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface.
The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.
A Unified Experimental Method and Model for Predicting Scale Inhibition
Authors: Dai Chong , Dai Zhaoyi , Zhang Fangfu , Zhao Yue , Deng Guannan , Harouaka Khadouja , Wang Xin , Lu Yi-Tsung , Paudyal Samiridhdi , Ko Saebom , Gao Shujun , Kan Amy T. , Tomson Mason 
Published: March 2019

Abstract
Scale formation that can hinder continuous oil production is a serious problem in oilfield. Among all common scales, barite and calcite are two of the most important scales. Scale inhibitors have been widely added to prolong the induction time of scales. This study evaluates the methods and previous inhibition models to measure and predict scale formation in the presence of phosphonate and polymer inhibitors under common brine conditions. Turbidity measurement with laser light was used accurately and quickly to measure the induction time, and good reproducibility can be achieved between different sources of inhibitors. By conducting a set of independent inhibition experiments, previous models were evaluated and the demand for model improvement was carefully pointed out. On the basis of these evaluations, new ScaleSoftPizer (SSP) model was proposed by incorporating all available data under various simulated oilfield conditions (4-175°C). The new SSP barite inhibition model was more internally consistent, and the new SSP calcite inhibition model expanded the applicable temperature ranges. The new SSP model was incorporated into SSP 2019. To prove the application of new SSP model, the predicted minimum inhibitor concentrations (MICs) were compared with lab observations and field data, which shows good consistence and improvements. This study improved the prediction of MIC over wide ranges of temperature and inhibitor types, which can significantly reduce the expenses and efforts to solve scale formation problems.
A More Effective Solution to Treat Paraffinic Crude Oil Wells
Authors: Phan T. , Faust M. , Balsamo V. , Champion Nalco 
Published: March 2019

Abstract
Production from highly paraffinic crude oil wells poses unique technical challenges such as poor flowability and paraffin deposition on the production tubing. Paraffin deposition increases the lift load on the pump, reduces pump efficiency, and eventually plugs the pump. To restore the productivity of these wells a common solution is to inject hot oil or hot water at 160°F–200°F to clean the deposits. This process imposes higher operating cost and lost production due to well downtime.
Paraffin inhibitor (PI) and pour point depressant (PPD) have been used to treat paraffinic fluids but are not effective for wells with high water cuts. These wells when treated with PI/PPD still require high cost maintenance such as the hot oil/water jobs and/or well workover. This paper presents a more effective treatment using tailored chemical mixtures to form a water dispersion with the paraffinic oil, thus to increase oil flowability and reduce deposition. A novel test method has been developed to evaluate effectiveness of treatment chemicals on various paraffinic oils based on flowability and cleanliness. The test method has been validated with field trial data from three different wells in the Uinta Basin, Utah and Julesburg Basin, Colorado.
The results of the field trials showed a significant increase in pumping efficiency and crude oil production. Need for hot water application was also reduced or eliminated for the treated wells. Improved oil and produced water quality were also observed. These results demonstrated that the water dispersion-based treatment is a more effective treatment for high paraffin wells with high water cuts.
Role of Surfactant Structures on Surfactant-Rock Adsorption in Various Rock Types
Authors: Wilson Daniel , Poindexter Laurie , Nguyen Thu 
Published: March 2019

Abstract
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.
What Can We Learn from Analysis of Field Asphaltenes Deposits? Enhancing Product Development Through Knowledge-Based Field-to-Lab-to-Field Approach
Authors: Da Silva de Aguiar Janaina Izabel , Pimentel Porto Mazzeo Cláudia , Garan Ron , Punase Abhishek , Razavi Syed , Mahmoudkhani Amir 
Published: March 2019

Abstract
Recent studies revealed that solids from lab-generated deposits often exhibit compositional differences from those of field deposits, pointing to a more complex fouling process in field operations. The objective of this work was to understand and apply knowledge from field deposit characteristics in order to design and conduct laboratory experiments which yield solid deposits with comparable compositional fingerprints. This approach allows a more objective and reliable product development and recommendation strategy to be adopted for increased success in the field applications. First, oil and deposit samples from an offshore field was characterized. Second, samples of the asphaltenes extracted from oil (AEO) and from the deposit (AED) were characterized based on solubility using an Accelerated Solubility Test (AST). A customized Asphaltene Dynamic Deposition Loop (ADDL) was used in this study to simulate the precipitation and deposition of asphaltenes from the crude oil. Crude oil used in the tests was from the same well where the deposits were collected. ADDL tests were conducted at high temperature and pressure and the composition of the collected deposit from this test was compared with the deposits from the field. At last, Light Scattering Technique (LST) was applied to screen asphaltene inhibitors (AI). Four candidate chemistries were tested on LST. To confirm the efficiency, the high performer was tested on ADDL under dynamic conditions. Deposits collected from the ADDL were characterized and results showed a high degree of similarity to the field deposit. AI1 was evaluated by ADDL and it decreased the deposition in the filters by 60% and 84% at 1000 ppm. This product was selected to be tested in the field and a plant trial is ongoing.
Effect of Fluid Loss Polymers Architecture on Cement Slurry Rheology : Impact of Adsorption and Microstructure
Authors: Cadix Arnaud , Molinie Vincent , Wilson James 
Published: March 2019

Abstract
Several polymer technologies are commonly used as fluid loss control additives. Working mechanisms were studied by Plank et al. (Plank et al. 2009) and most of the time these can be classified into 2 categories: adsorbing polymers and pore plugging "microgel" like systems. In addition, these polymers have a strong influence on the cement slurry rheology and are also often expected to play a role on cement particle suspension, cement sheath homogeneity and to prevent settling.
The scope of this paper is to investigate the impact of several types of fluid loss polymers on cement slurry stability. Then, an effort is made to correlate the working mechanism of the fluid loss additive with cement slurry rheological behavior and its ability to prevent segregation or settling.
On top of conventional tests on fluid loss and flow rheology, refined evaluations of the rheological behavior are performed in oscillatory rheometry at very-low strain. This technique allows some insight into the microscopic interactions at stake in cement slurries. In particular a "yield stress model" is applied to formulated oil well cement slurries at 90°C providing additional insight on the impact of adsorbing or non-adsorbing polymers.
From this study it can be confirmed that adsorbing polymers have a strong impact on rheological properties with a surprisingly lower yield stress combined with improved slurry stability. On the other hand non adsorbing polymers of either linear or μgel form have a very limited impact on slurry yield stress and a variable impact on slurry stability through either viscosification of the interstitial fluid for linear polymers or enhanced settling hindrance from μgels.
Experimental Study on the Synthesis and Interfacial Properties of Oligomeric Silicone Surfactant
Authors: Jie Zhang , Xu Xianguang , Wang Lihui , Li long , Zhang Die , Zhao Zhiliang , Wang Shuangwei 
Published: March 2019

Abstract
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).
Roles of the Hydrophobic Tail Groups on the Properties of CO2-Switchable Surfactants
Authors: Hou Qingfeng , Wu Qi , Xu Yan , Zheng Xiaobo , Zhao Yujun , Wang Yuanyuan , Guo Donghong , Xu Xingguang 
Published: March 2019

Abstract
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 (Lu 2014). However, the influence of hydrophobic tail groups on the properties of CO2-switchable surfactants in the protonation and emulsification has not yet been well elucidated. In this work, a series of acetamidines with differing hydrophobic tail group were synthesized, and the synthesis conditions were optimized. The effect of the hydrophobic tail group on the conductivity and emulsion stability were also investigated in details. All the acetamidines presented an excellent switchable property in the conductivity test. Compared to the surfactant with shorter hydrophobic tail group, the acetamidine bicarbonate with longer hydrophobic tail group presented a faster deprotonation rate during bubbling N2. Shorter hydrophobic tail group was beneficial to the protonation of the acetamidines in the presence of CO2, resulting in the formation of hydrophilic bicarbonates compound. However, these bicarbonates with shorter hydrophobic groups were more difficult in deprotonation during the bubbling N2 stage. To examine the emulsifying ability of N'-alkyl-N,N-dimethylacetamidines with different hydrophobic tail groups, emulsifying experiments were conducted at 30°C using a mixture of oil-water containing as synthesized acetamidines (0.1%wt.). The mixture of dodecane-water formed an emulsion after bubbling CO2. The variation in phase separation should be ascribed to the different length of hydrophobic groups of these acetamidines. This revealed the correlation between tail group carbon numbers and hydrophobicity.
PDEA-Based Amphiphilic Polymer Enables pH-Responsive Emulsions for a Rapid Demulsification
Authors: Hou Qingfeng , Zheng Xiaobo , Guo Donghong , Zhu Youyi , Yang Hui , Xu Xingguang , Wang Yuanyuan , Chen Gang , Hu Guangxin , Wang Jinben 
Published: March 2019

Abstract
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.