bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Viscoelastic Fluid for Chemical EOR
Authors: Morvan Mikel , Degré Guillaume , Leng Jacques , Masselon Chloé , Moreau Patrick , Bouillot Jérôme , Zaitoun Alain 
Published: April 2009

Abstract
This work aims at evaluating a new surfactant based viscoelastic fluid for Chemical EOR applications. The surfactant based fluid exhibits a viscous phase at low concentration and high temperature, useful for improving oil recovery.
The viscoelastic fluid is induced by wormlike micelles formed by self-assembled surfactants. The phase diagram of the surfactant in pure water was established using a pervaporation-based microfluidic device (Leng et al., PRL, 96, 2006). Isotropic wormlike micelles have been observed up to 12 % w/w. In a second step, Particle Tracking Microrheology (PTM) was used to investigate the rheological properties of the fluid for surfactant concentrations below 2% w/w in water. Viscosity at low surfactant concentrations (0.1% to 0.3 % w/w), T= 80°C, in synthetic sea water (3.9 % w/w TDS) and in sodium chloride (2 % w/w TDS) has been recorded. Data shows that the viscosity is weakly dependent on brine concentration and evolves between 3 and 15 mPa.s (γ=10 s-1), for surfactant concentrations between respectively 0.1% to 0.3 % w/w.
The second series of tests consisted of core-flood experiments at 80°C in Clashach sandstone with brine solution (NaCl 2% w/w) containing surfactant concentrations between 0.1 %w/w and 0.3 %w/w. The surfactant is shown to adsorb moderately on the sandstone (50 μg/g) and displace a great fraction of residual oil (from Sor=0.49 to Sor=0.20).
These preliminary results show a strong potential for this new surfactant based viscoelastic fluid in chemical EOR. Compared to other viscoelastic fluids this product shows the following advantages:
Superior viscosity, at low surfactant concentration, in hard brine and at high temperature Better displacement of residual oil in core-flood with moderate adsorption
Successful Scale Mitigation Strategies in Saudi Arabian Oil Fields
Authors: Raju Kris U. 
Published: April 2009

Abstract
Scale deposition, either in the formation or in the production facilities, is a challenging problem in the petroleum industry. Scale mitigation and prevention programs are critical for sustained oil production. It is therefore essential to put in place proper scale management strategies before developing a new field. In addition, exploring new chemical formulations and treatment strategies for current field programs should be examined on a continuous basis to ensure efficient results are achieved.
Saudi Arabian reservoirs have their own set of scale related challenges. Calcium carbonate scales were a major challenge in a majority of wet producers in several carbonate reservoirs across Saudi Arabia. The possibility of a sulfate scaling problem in these fields was minimized by selecting compatible floodwaters and/or creating a sufficient buffer-band to separate the incompatible waters. Phosphonate based scale inhibitor treatments, either encapsulated chemical applied in the rathole or squeezed into the formation, have been highly successful. This has been attributed to the relatively low scaling potentials and associated low threshold inhibitor concentrations, an effective sampling and monitoring strategy and a proactive approach to managing the scaling problem.
Over recent years, well architecture has become more complex, requiring innovative scale mitigation strategies. Vertical wells have been replaced with horizontal wells, horizontal wells with multilaterals, and multilaterals with maximum reservoir contact wells. The future wells include extreme reservoir contact and it is imperative to develop viable and cost-effective treatments for this variety of well types. This paper details how Saudi Aramco mitigated difficult to handle sulfate scaling problems with proper selection of floodwaters in various fields, describes the theoretical background in selecting simple and inexpensive bullhead scale inhibitor squeeze treatments for horizontal wells. We also present technical and economic reasoning for the successful scale management strategy in Saudi Aramco fields with case histories.
Integration of Kinetics into Scale Prediction Software, ScaleSoftPitzer
Authors: Tomson Mason , Fan Chunfang , Lu Haiping , Zhang Ping , Alsaiari Hamad , Kan Amy T. 
Published: April 2009

Abstract
As water cuts increase world wide it becomes more important to control the adverse effects of injected and produced waters. The challenges are greater due to the wider ranges of T, P, and compositions of injection and production fluids. Both equilibrium and rate processes are important to scale and corrosion control. The Brine Chemistry Consortium (BCC) at Rice University has expanded the range of its software to include prediction of brine pH, scale supersaturation for common oilfield scales, mass transport, and the effect of various concentrations of scale inhibitors in the presence and absence of hydrate inhibitors, over a temperature range of about 32 to 400 °F (0 to ≍200 °C), or greater, and pressures from atmospheric to between one and two thousand atmospheres. Many of these models are based upon data developed at the BCC. Comparatively, only limited work has been done to model the kinetics under conditions important to production.
Models have been developed and tested experimentally to include the effects of both methanol (MeOH) and mono-ethylene glycol (MEG) on pH, scale formation, and inhibitor kinetics from zero to 100% MeOH or MEG over the range of conditions commonly found. It has been found experimentally and justified theoretically that once the effect of MeOH or MEG on supersaturation has been modeled, the impact on minimum inhibitor concentration (MIC) and nucleation kinetics for common scales is readily predicted. Even less work has been done to characterize the effects of cosolvents on kinetics.
In order to model small changes in composition, as can be important with iron/zinc, etc., carbonates and sulfide formations, a new high efficiency algorithm that incorporates several numerical methods simultaneously has been developed to assure calculation fidelity even in extreme ranges of composition. Limiting equations will be developed that incorporate some kinetics into brine chemistry modeling for flow in porous media and for flow in pipes.
Modelling Staged Diversion Treatments and Chemical Placement in the Presence of Near Wellbore Fractures
Authors: Stalker Robert , Graham Gordon M. , Oluyemi Gbenga 
Published: April 2009

Abstract
The placement and return of chemical treatments in the near wellbore region is often complicated by a number of factors. For long heterogeneous wells, it is often the case that simple bullhead injection of chemicals can fail to effectively treat the whole length of the well, resulting in key producing intervals being left underprotected and at risk of premature scale-up, impacting oil production. In such cases, the adoption of a more complex staged diversion treatment program can pay dividends, resulting in more effective placement of scale inhibitor and, consequently, longer field return lifetimes. The placement of chemicals in the near-wellbore region can also be perturbed by the presence of fractures. Appropriate modelling of the effect of near-wellbore fractures on chemical placement and return can be difficult, with extensive variations in fracture dimensions and orientations making it difficult to directly measure fracture-network geometry in sufficient detail to model its effect on chemical placement in the near wellbore regions of fractured reservoirs.
In this paper we examine the impact of both artificial and natural micro-fractures on the predicted penetration distance and placement behaviour of injected treatment chemicals, and the consequences of this for inhibitor returns in fractured reservoirs. The paper also presents the results of a series of laboratory tests which provide validation of the fracture model. We also describe the use of a near-wellbore placement simulator to model the placement and chemical return of staged diversion treatments and the impact of these techniques on overall well returns. The algorithms associated with both cases have been incorporated into a new near wellbore simulator and the results compared in a number of case studies. The paper describes the modelling approach and demonstrates its use in modelling near-wellbore chemical placement and propagation.
An Environmentally Friendly Stimulation Fluid for High Temperature Applications
Authors: LePage J. N. , De Wolf C. A. , Bemelaar J. H. , Nasr-El-Din H. A. 
Published: April 2009

Abstract
Matrix acidizing is used in carbonate formations to create flow channels from the formation to the well bore, whereas in sandstone formations the goal is to dissolve materials that impair the well production. However, the use of acids in deep wells has some major drawbacks including high reaction rate and corrosion to well tubulars.
We have discovered a new stimulation chemical that can be used as a replacement for or in combination with acid treatments in deep wells. A polyacid whose structure allows for acidification is described. The polyacidic chelate L-glutamic acid, N,N-diacetic acid or GLDA is manufactured from L-glutamic acid (MSG). The chelate-based fluid very effectively dissolves CaCO3 and it is less corrosive to the equipment and easy to handle.
This paper discusses the reaction of the new GLDA chelate with calcite and will compare its performance with other available chelates, including EDTA, HEDTA, NTA and EDG. GLDA dissolves calcite over a wide pH interval, although it is less effective than HEDTA at &gt; pH 5. A unique property of GLDA is its high solubility - solutions exceeding 40 wt% can be achieved at a ~ pH 2 where HEDTA solubility is limited to ~ 10 wt%. A mole of GLDA acid with a natural ~ pH 1.6 is capable of dissolving up to two moles of CaCO3. Throughout the pH range GLDA appears to be as thermally stable as HEDTA.
As an additive to HCl, GLDA is as effective as HEDTA in preventing precipitation of moderate levels of Fe in spent acids. At high Fe concentration GLDA is slightly less effective than HEDTA on a molar basis – but to deal with high Fe GLDA may be better as significantly higher concentrations of it are possible in various acids. In 28 wt% HCl, HEDTA has limited solubility while GLDA's solubility exceeds 40 wt%.
From an environmental standpoint GLDA, is readily biodegradable and is made from a renewable raw material – monosodium glutamate. GLDA has low toxicity and aquatic toxicity characteristics. As a replacement for HCl acid, GLDA is significantly safer and is less corrosive.
Rheological Properties of a New Class of Viscoelastic Surfactant
Authors: Li L. , Cawiezel K. E. 
Published: April 2009

Abstract
Surfactant-based acid systems were developed over the last few years for diversion to overcome the severe problems caused by polymer residue and crosslinker precipitate after polymer-based system treatments during matrix and fracture acidizing. Two main types of viscoelastic surfactants have been used: amphoteric and cationic. Surfactant molecules can form rod-like micelles and significantly increase the viscosity in the presence of the salts. After acid treatments, the surfactant gel can be broken by mixing with hydrocarbons, external breakers, and internal breakers or by reducing the concentration of salts via dilution with water.
This paper introduces a new type of viscoelastic amphoteric surfactant (amine oxide). It carries a positive charge in the presence of live HCl acid. The effects of acid additives and Fe (III) contamination were examined on its rheological properties. Measurements were made at temperatures from 75-220 °F, and 300 psi at various shear rates from 0.01-935 s−1. Acid additives included corrosion inhibitors, mutual solvent, non-emulsifying surfactant, iron control agents and hydrogen sulfide scavenger.
The apparent viscosity of surfactant solutions prepared in deionized water, live acid, and spent acid was found to be a function of temperature. Calcium chloride increased the apparent viscosity of live acids. Concentration of HCl in the live acid system affected its apparent viscosity. Live acid that contained 12 wt% HCl showed the highest apparent viscosity. Low concentrations of Fe (III) caused an increase in the apparent viscosity. Two immiscible liquids, and then a precipitate were noted as the concentration of ferric ion was increased in live acids. A demulsifer and mutual solvent decreased the apparent viscosity at all temperatures examined. Iron control agents reduced the apparent viscosity of surfactant based acids. The impact of lactic acid on the apparent viscosity was significant, especially at high lactic acid concentrations. Citric acid also reduced the viscosity of surfactant based acids, but cannot be used at concentrations greater than 0.5 wt% because of precipitation of calcium citrate. EDTA slightly reduced the viscosity of surfactant based acids, but the solubility of EDTA in 20 wt% HCl is very low. Up to 1 wt% methanol can be used with this spent acid system at temperatures below 175°F. Higher concentrations of methanol caused significant reduction in the apparent viscosity.
Fast-Inverting, Brine and Additive-tolerant Friction Reducer for Well Stimulation
Authors: Zelenev Andrei S. , Gilzow Gydeon A. , Kaufman Phillip B. 
Published: April 2009

Abstract
Anionic polyacrylamide copolymer friction (or drag) reducers are commonly used in various well stimulation jobs. The effectiveness of friction reduction polymers strongly depends on the compatibility between friction reducing polymers and stimulation liquid to which they are added. Performance of friction reducers can be strongly influenced by the presence of salts, very high or very low pH, or other typical process additives, such as biocides, corrosion and scale inhibitors, hydrogen sulfide (H2S) scavangers, etc. Since most friction reducers are emulsion polymers, an important issue related to their performance is their ability to invert effectively and efficiently upon the addition to the stimulation fluid. A fast enough rate of inversion is especially important, since it determines both the effective onset of optimal friction reduction and its magnitude. Higher friction reduction achieved at the very beginning of a well stimulation will decrease the pumping pressure on a job. We hereby describe novel, fast-inverting friction reducers suitable for effective use in brines and compatible with various additives, such as biocides, clay control agents, and scale inhibitors.
Theoretical Study on the Properties of Cationic, Amidoamine Oxide and Betaine Viscoelastic Diverting Surfactants in Gas and Water Solution
Authors: Sultan A. S. , Balbuena P. B. , Hill A. D. , Nasr-El-Din H. A. 
Published: April 2009

Abstract
pH-sensitive surfactants are becoming increasingly important in many novel applications in various fields including medicine, fabrication, sensing, optics, and oilfield. For upstream industry, it can be used in drilling operation, hydraulic fracturing, acidizing treatments, and sand control. The widespread applications of viscoelastic surfactants (VES) originate from the intrinsic duality in their molecular characteristics. Through many years of experience, various classes of VES have been introduced including cationic, zwitterionic (betaine) and especially, alkylamine oxide surfactants which represent a promising and well-characterized class of responsive fluid. These materials have considerable influence on acid placement in oil well stimulation. As the acid reacts with carbonate minerals in particular, the pH rises and the concentration of calcium chloride, magnesium chloride, or both will increase. The presence of salts and the increase in pH will cause the surfactant molecules to form long rod-like micelles. The behavior of wormlike micelles have drawn considerable interest over the past two decades, both from a theoretical viewpoint as well as for industrial and technological applications, the range of which keeps expanding.
The objective of this paper is to focus on the interaction of different types of surfactant with water using density functional theory (DFT) and classical molecular dynamics (MD) simulations. The structural and energetic properties of five-cationic, four-amidoamine oxide, and six-betaine head groups, (all of which are well known importance for the design of efficient VES acid diverters), are calculated with Hartree-Fock and DFT methods in gas phase and water solution. The conformational behavior of the molecules is studied using the analysis of thermodynamic properties. The information obtained may serve to understand the electronic origin of the factors that determine the properties of these simple molecules and to get insight into the more complex ones in which the tail is not a single methyl group rather a chain of C18-C22, and how they are affected by the water environment.
Mitigation of Reservoir Souring by Nitrate in a Produced Water Re-Injection System in Alberta
Authors: Arensdorf J. J. , Miner K. , Ertmoed R. , Clay B. , Stadnicki P. , Voordouw G. 
Published: April 2009

Abstract
We report the reduction in levels of H2S in produced gas and water using nitrate treatment in an oilfield in Southern Alberta that is under produced water re-injection. Approximately 4,500 m3/day of water is injected, primarily produced water supplemented with make-up water from the outfall of a municipal waste treatment plant. The reservoir is 30-40°C. Calcium nitrate was continuously applied at 150 ppm (as nitrate) into the injection water at a central water plant and distributed to injection wells field wide. A biocide, acrolein, was also applied in weekly batches to treat the injection lines and prevent nitrate-fed biofilm accumulation. After one month of treatment, H2S in the produced gas from one gathering system dropped from an average of 170 ppmv to 110 ppmv (average 3.4 kg/day to 1.8 kg/day). This represents an approximately 50% reduction in produced H2S in the gas. A corresponding decrease in H2S in the produced water was observed. One problematic well maintained an H2S level of approximately 800 ppmv. To treat this well, a nearby injector was started on a weekly treatment of a single batch of calcium nitrate dosed to approximate 600 ppm, based on a seven-day production rate. Sulfide levels in the problem well dropped significantly and over the subsequent 18 months there has been on average &lt;15 ppmv H2S in the produced gas.
Design and Development of a Novel Process To Treat Drilling Fluid Slops: A Positive Environmental and Economic Impact
Authors: Dixit Rahul , Patel Arvind 
Published: April 2009

Abstract
Slop mud, created by water contamination of invert drilling fluids during displacement and cleaning activities, has been successfully treated at source to recover the drilling fluid phase and water phase. This method included treating the slop mud with a biodegradable demulsifier. The recovered drilling fluid can be reconditioned to acceptable properties for re-use or sent for disposal. The recovered/separated slop water phase is contaminated with hydrocarbons and cannot be discharged in an offshore environment unless it meets the discharge criteria of &lt;30 mg/L of oil-in-water. Thus, it becomes imperative for the operator to treat the water at source and reduce the enormous expenses associated with transportation /disposal and embark upon a potentially significant environmental issue. This was achieved by development of an onsite treatment process including filtration, ozonation and phase separation.
A synthetic-based drilling fluid contaminated with water was separated with a biodegradable demulsifier. The addition of the surfactant resulted in phase separation, i.e., separated drilling fluid and water phases. As tested by the approved ISO method, the separated water phase was found to have oil-in-water content of 4,000 mg/L which is unacceptable for discharge. The separated water was then treated with ozone. The ozone-treated water was allowed to separate in two phases, i.e., clarified water phase and organic rich phase. The oil-in-water content of the clarified ozone-treated water phase was found to be 30 mg/L, thus reducing the oil-in-water content by 99%.
This paper will present the demulsification methodology, chemistry of ozonolysis and results obtained to meet or exceed the oil-in-water discharge limits of 30 mg/L. The environmental and economic impact of the process will be discussed.
Lab and Field Study of New Microemulsion-Based Crude Oil Demulsifier for Well Completions
Authors: Yang Y. , Dismuke K. I. , Penny G. S. , Paktinat J. 
Published: April 2009

Abstract
In the petroleum industry, water and oil emulsion formation presents an on-going production issue receiving considerable technical attention. Crude oil/water demulsification effectiveness has been tested using a new microemulsion-based demulsifier (ME-DeM) with an environmentally improved formulation. This ME-based product, tested on a range of crude oils, has been shown to be more effective than comparable commercially available non-ME based demulsifiers (DeM). Results using ME based products for demulsification have demonstrated significant improvements in field tests. Additional field studies are in preparation.
Low Molecular Weight Co-Polymer for Calcium Scale Inhibition at High Temperature
Authors: Senthilmurugan B. , Ghosh B. 
Published: April 2009

Abstract
Calcium scaling problem in production tubular is the most widespread among flow assurance problems. Well intervention in every 3-4 months are common to combat calcite deposition and rapid production decline. In order to minimize the formation of scale deposits, threshold scale inhibitor treatment with polycarboxylates or Phosphorous containing compounds (such as phosphonates or phosphate esters) are common practice in oil industry. In general the polycarboxylates rarely provide optimum performance against calcium carbonate. Higher molecular weight acrylate base products often precipitate as calcium salt. Phosphorous containing scale inhibitors has good overall treatment efficiency, however increasing pressure by environmental regulatory authorities has promulgated search of newer and greener threshold scale inhibitors.
This paper describes synthesis, characterization and efficiency of a high temperature stable, threshold scale inhibitor which is found to work well in low doses at a wide range of pH and temperature. A low molecular weight, maleic acid base co-polymer is synthesized, characterized and inhibition efficiency was compared for calcium carbonate scaling. Molecular weight of the polymer was determined through GPC. FT-IR spectroscopy was used for functional group distribution pattern. Scale inhibition efficiency was measured through chemical screening test, dynamic tube block method and also through electrochemical technique such as constant potential electrolysis and electrochemical impedance techniques. XRD and SEM analysis demonstrated inhibited and un-inhibited crystal structure.
The copolymers showed +90% efficiency in 15-20 ppm dosing at common wellbore temperature (upto 100 °Ċ). For even higher temperature (+120 °C) dose requirement is more. Excellent inhibition property is demonstrated against calcium carbonate scale deposition. Electrochemical studies supported the static and dynamic test results. SEM images demonstrated the scale inhibition of the polymers through adsorption on the growing crystal phases of the nuclei, which resulted in distortion and retardation of crystal growth.