9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Welcome from the Conference Chairman

On behalf of the Conference Organizing Committee, it gives me great pleasure to welcome you to the 9th International Conference on Petroleum Phase Behavior and Fouling. In order to meet the high standards set by previous conference organizers, the committee has spent a great deal of time and effort on arranging the technical and posters sessions as well as the social events for what we hope will be a memorable 2008 Conference!

Each year the conference seeks to provide academic and industry researchers with an opportunity to share new developments in the area of phase behavior and fouling. This year, 37 oral presenters will share their research in five technical sessions: Thermodynamics and Rheology of Petroleum Fluids, Asphaltenes, Emulsions, Flow Assurance and Upgrading & Refining.

The two poster sessions will provide over 60 poster presenters with an opportunity to “present” their work twice during their session. Seven to eight presentations will occur simultaneously every fifteen minutes over the course of two hours and delegates will choose which presentations they wish to hear. We believe this format will be a positive experience for both the presenter and the audience.

I am also delighted to welcome you to Victoria, one of my favorite Canadian cities! The social event schedule aims to allow you to enjoy some of the area’s main attractions. Victoria’s heritage will be evident with tea at the Empress, dinner at the Royal British Colombia Museum will highlight some of the cultural and natural history of the area, while the whale watching and Butchart Garden tours will provide an opportunity to enjoy nature’s beauty. I sincerely hope that you find Petrophase 2008 an event to remember!

Moin Muhmammad

Sponsors

Thank you to our sponsors! Without their generous support the conference would not be possible.

Platinum Silver Support

Bronze Gold

1 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

“Petrophase 2008 at a Glance”

Date Morning Afternoon Evening

Registration and Opening Sunday, June 15 Reception

8:00 – 8:15 AM Welcome & Conference Opening

8:15 AM – 12:30 PM 1:00 – 2:30 PM Thermodynamics and 6:00 – 9:00 PM Tea at the Empress Rheology of Petroleum Poster Session I Monday, June 16 Fluids 2:30 – 6:00 PM Shawn Taylor* Free Time Jean-Francois Augillier** Peter Seidl** Jill Buckley* Bill Power* Harvey Yarranton*

8:00 AM – 10:00 AM Asphaltenes I (AI) 1:00 PM – 2:30 PM Asphaltenes II 10:15 AM – 12:15 PM Asphaltenes II (AII) 2:30 PM – 6:45 PM 7:30 PM Emulsions Conference Dinner Tuesday, June 17 John Nighswander** (AI) Royal British Colombia Duy Nguyen** (AI) George Hirasaki** Museum Eric Sirota** (AII) Jannie Beetge** Steve Allenson** (AII) Jan Czarnecki* Oliver Mullins* Jean-Francois Argillier* Simon Andersen* Peter Kilpatrick* John Shaw*

8:00 AM – 12:45 PM Flow Assurance 6:00 PM – 9:00 PM 1:30 PM – 6:00 PM Jeff Creek** Poster Session II Wednesday, June 18 Whale Watching or David Jennings** Butchart Garden Tour George Broze* Shawn Taylor* Anil Mehrotra* Shawn Taylor*

8:00 AM – 12:15 PM Upgrading and Refining

Frans van den Berg** Paul Watkinson** Murray Gray* Thursday, June 19 Milind Deo* Howard Freund*

12:15 – 12:45 PM Conference Wrap-Up 2009 Announcement Closing Remarks

** Session Co-Chair * Session Organizer

Technical sessions take place in the Main Ballroom of the Delta Ocean Point

Poster sessions take place in the Harbour Room

2 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Organizing Committee

Irwin (Irv) Wiehe Moin Muhammad John Ratulowski Soluble Solutions Schlumberger Schlumberger Conference Co-Chair Conference Chair Technical Chair

Technical Committee

Jean-François Argillier Jill Buckley Institut Français Simon Andersen George Broze Jan Czarnecki du Pétrole Topsøe New Mexico Institute of Shell Mining and Technology University of Alberta

Jean-Luc Daridon Gaspar Gonzales Milind D. Deo Howard Freund Université de Pau Murray Gray Petrobras University of Utah ExxonMobil University of Alberta

Peter Kilpatrick Peter Siedl North Carolina Anil Mehrotra Oliver Mullins Bill Power Federal University of State University University of Calgary Schlumberger Shell Rio de Janeiro

John M. Shaw Shawn Taylor Harvey Yarranton University of Alberta Schlumberger University of Calgary

3 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Thermodynamics and Rheology of Petroleum Fluids Session Co-Chairs

Jean-François Argillier is manager of Improved Oil Peter Rudolf Seidl is an Recovery (IOR) thematics at Industrial Chemist by the IFP, in the E&P technology Federal University of Rio de business unit, with responsibility Janeiro (UFRJ) and holds a as research project leader in PhD from the University of heavy oil production, EOR California Los Angeles (UCLA). technologies and well injectivity /productivity.

He has been a Professor at the Military Institute of His research focuses on colloidal systems and Engineering (IME) and the Federal Universities of Rio complex fluids in oil applications, in particular Grande do Sul (UFRGS) and Fluminense (UFF). He polymers, surfactants, asphaltenes, emulsions, was President of the Brazilian Chemical Association foams, scales, that could be encountered in heavy oil (ABQ), Scientific Director for the State of Rio production, drilling fluids, well productivity impairment Research Foundation (FAPERJ) and Program and enhanced oil recovery. Coordinator for the National Scientific and Technological Council (CNPq). He is presently Jean-Francois graduated at Ecole Supérieure de Professor at the Graduate Program in Chemical and Physique et Chimie Industrielles de Paris (ESPCI) Biochemical Processes of the School of Chemistry of and holds a PhD from University Pierre et Marie the UFRJ and Visiting Researcher of the Human Curie, Paris VI. (1989) in Chemical engineering. He Resources Program of the National Agency for had a postdoctoral position at the University of Petroleum, Natural Gas and Biofuels (PRH/ANP), Minnesota (USA) in 90-91. He joined IFP in 1993. working in Physical Organic Chemistry and Jean-Francois is member of SPE and SFC, served in Petroleum Chemistry. He also is organizing the different organizing committees (SPE Forum, ..), is Brazilian Green Chemistry School. co-author of 30 patents and of various publications on colloidal systems in oil applications.

Thermodynamics and Rheology of Petroleum Fluids Session Keynote Speaker

Professor Walter G. Chapman is the William W. Akers Professor of Chemical and Biomolecular Engineering and the Director of the Energy and Environmental Systems Institute at Rice University. Among his awards are multiple teaching awards and an Outstanding Young Alumni Award from Clemson University. Professor Chapman is widely recognized for his research into properties and interfacial structure of complex fluids with applications in the energy and high performance materials industries. Before joining the faculty at Rice, Walter was a Research Engineer with Shell Oil Company.

4 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008 Monday, June 16 THERMODYNAMICS AND RHEOLOGY OF PETROLEUM FLUIDS Time Speaker Title AB # A Method for the Prediction of Boiling Point 8:15 AM P. Peczak Curve of Heavy-Hydrocarbon Residua Based on 1 Solubility Data Phase Behaviour of Heavy Oils and Bitumen - an 8:45 AM J.M. Shaw 2 Approach Based on Calorimetry and Rheology Isothermal Pressure Effect on Asphaltene Phase 9:15 AM A.A. Hamouda 3 Behavior Application of the PC-SAFT EoS in the definition 9:45 AM F. Vargas 4 of a Universal Plot for Asphaltene Stability 10:15 AM Coffee Break S.E. Quinones- Modeling and Prediction of Non-Newtonian 10:30 AM 5 Cisneros Viscosity of Crude Oils Rheological Characterization under Pressure of 11:00 AM P. Abivin 6 Foamy Oils and Live Heavy Oil Emulsions 11:30:00 AM Modeling Asphaltene Phase Behavior in Crude Walter Chapman 7 (KEYNOTE) Oil Systems

5 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Aspaltenes Session I Co-Chairs

John Nighswander is Technical Dr. Duy Nguyen is Research & Manager and Schlumberger Development Manager in the Advisor in Reservoir Fluid Production Optimization group at Sampling and Analysis, based Nalco, where he is responsible for in Houston. John began his development of foamers for career in 1989 with DB increasing gas production, Robinson and Associates Ltd. antifoams, demulsifiers, and water (DBR), at Edmonton, Canada. clarifiers.

John held various positions in DBR including He joined Nalco 15 months ago. Prior to joining President of DBR Fluid Properties Inc., in Houston. Nalco, he was with Hercules in the Paper Division John joined Schlumberger in 1998 and acted as and then with Huntsman. Dr. Nguyen is the author or Product Development Manager and Business coauthor of nine professional papers and the holder Development Manager for Schlumberger’s or coholder of 23 U.S. patents. He was the recipient Oilphase Division based in Aberdeen, Scotland. In of R&D Outstanding Achievement Award and 2004 John returned to Houston as the Global Fluids Corporate Technical Achievement Award. He was Business Manager for Schlumberger. In 2006, he the invited speaker at the North America Gas Well started his current role managing a proprietary Deliquification Conference, European Gas Well product development project. John received B.Sc. Deliquification Conference, American Oil Chemists’ (1986) and Ph.D. (1989) degrees in chemical Society, American Chemical Society, and engineering from the University of Calgary. International Coatings Exposition. His research interests center on interfacial stability, emulsions and microemulsions, and enhance oil recovery processes. Dr. Nguyen received a B.S degree in chemical engineer from Louisiana State University and a PhD in colloid and surface chemistry from the University of Missouri-Rolla.

Aspaltenes Session II Co-Chairs

Dr. Eric B. Sirota is a research Steve Allenson graduated scientist at Corporate Strategic from Texas Tech University Research of ExxonMobil in 1977 in Chemistry. After Research & Engineering graduation he joined Nalco Company. Co. and has been with them his entire career. He has 31 He joined Exxon as a post- years experience in paraffin, doctoral fellow after receiving a PhD in Physics from asphaltene and hydrate Harvard University in 1986. His area of research is deposition control. the physical properties of heavy hydrocarbons, ranging from well-defined alkanes ("wax") to He has designed and managed paraffin and asphaltenes. In 2002, he was elected a Fellow of asphaltene control programs in numerous the American Physical Society for “pioneering use of deepwater offshore facilities throughout the world. x-ray scattering techniques in soft condensed matter, Steve is well published and has been a presenter at particularly regarding bulk and surface physics of numerous conferences. He is presently the Chief alkyl-chain compounds.” Technologist for Nalco’s Flow Assurance and Ultradeepwater group. He is married to the artist, Cara London and they have 2 children, ages 11 and 12. During any Steve is married with two grown daughters and lives remaining spare time he is a composer, his first major in Richmond Texas with his wife Sharon and their work being a musical "Day of Wrath" based on two dogs. Shelley's Frankenstein.

6 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008 Tuesday, June 17 ASPHALTENES I Time Speaker Title AB # 8:00 AM Honggang Zhou Investigations on Asphaltenes Precipitate Properties 8 Nanocolloidal Dispersion of Asphaltenes in (Reservoir) 8:30 AM Oliver C. Mullins 9 Crude Oil 9:00 AM Eric Sirota Asphaltene -Resin Association 10 9:30 AM Tabish Maqbool Kinetics of Asphaltene Precipitation from Crude Oils 11 10:00 AM Coffee Break ASPHALTENES II Time Speaker Title AB # Understand the Intriguing Solubility Properties of 10:15 AM Honggang Zhou 12 Asphaltenes in Apolar Solvents SANS Experiments and Molecular Dynamics Studies of 10:45 AM T. F. Headen Asphaltenes: Driving Force and Morphology of Nano- 13 aggregation Investigation of the Effects of Water on Aggregation of 11:15 AM Xiaoli Tan 14 Model Asphaltenes in Organic Solution

Asphaltene Adsorption and Deposition Mechanisms Probed at the Local Scale Under Static and Dynamic 11:45 AM Loïc Barré 15 Conditions: a New Opportunity of Neutron In-situ Rheo- Reflectivity Measurements. 12:15 PM Lunch in the Conference Room Andrew E. Two-Step Laser Desorption Laser Ionization Mass 1:00 PM 16 Pomerantz Spectometry of Asphaltenes

Fourier Transform Ion Cyclotron Resonance Mass 1:30 PM Alan Marshall Spectrometry: The Most Powerful Tool for Compositional 17 KEYNOTE Characterization of Petroleum and Its Relatives

Aspaltenes Session Keynote Speaker

Alan G. Marshall completed his B.A. degree with Honors in Chemistry at Northwestern U.in 1965, and his Ph.D. in Physical Chemistry from Stanford U. in 1970. He joined the Chemistry faculty at the University of British Columbia (Vancouver, Canada) in 1969. He moved to Ohio State University in 1980 as Professor of Chemistry and Biochemistry and Director of the Campus Chemical Instrument Center. In 1993, he moved to Florida State University, where he is Robert O. Lawton Professor of Chemistry and Biochemistry and Director of the Ion Cyclotron Resonance (ICR) Program, an NSF national user facility. He co- invented and leads the continuing development of Fourier transform ICR mass spectrometry.

His major recognitions include:Fellow, American Physical Society; Fellow, American Association for the Advancement of Science; Fellow, Society for Applied Spectroscopy; three American Chemical Society national awards (Chemical Instrumentation, Field-Franklin Award, and Analytical Chemistry Award); two Spectroscopy Society of Pittsburgh Awards (Hasler Award and Spectroscopy Award); American Society for Mass Spectrometry Distinguished Contribution Award; International Society for Mass Spectrometry Thomson Medal; and Chemical Pioneer Award from American Institute of Chemists. He is a former President of the American Society for Mass Spectrometry, and serves on several editorial boards. He has published four books, four patents, and 460 refereed journal articles, and has presented 1,400 talks/posters at conferences, universities, government labs, and industry. His papers have been cited 16,000 times. His current research spans FT-ICR instrumentation development, fossil fuels and environmental analysis, and mapping the primary and higher-order structures of biological macromolecules and their complexes. 7 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Emulsion Session Co-Chairs

George J. Hirasaki has a Jan H. (Jannie) Beetge took on B.S. in Chemical some of the many challenges in Engineering (1963) from oilfield chemistry when he joined Lamar University and a the research team of Champion Ph.D. in Chemical Technologies, Inc. in June of Engineering (1967) from 2002. He grew up in South Africa Rice University. where he completed his B.Sc. degree in chemistry and physics George had a 26-year career in 1983, followed by a B.Sc. with Shell Development and Hons. degree in chemistry in Shell Oil Companies before 1984 and a M.Sc. in physical joining the Chemical chemistry in 1985. Engineering faculty at Rice University in 1993. In 1992 he received a Ph.D. in physical chemistry; all degrees awarded by The University of the Orange At Shell, his research areas were reservoir Free State. Academic research experience focused simulation, enhanced oil recovery, and formation on synthesis, reaction mechanism and kinetics of evaluation. At Rice, his research interests are in organometallic complexes of rhodium. His industrial NMR well logging, reservoir wettability, surfactant career started at The Atomic Energy Corporation of enhanced oil recovery, gas hydrate recovery, SA where he gained experience in various aspects of asphaltene deposition, emulsion coalescence, and uranium enrichment. He later played a leading role in surfactant/foam aquifer remediation. He received the effort to commercialize technology from the the SPE Lester Uren Award in 1989. He was named enrichment program. These include the development an Improved Oil Recovery Pioneer at the 1998 of polymeric hollow fiber membranes for gas SPE/DOR IOR Symposium. He was the 1999 separation and process development for the recipient of the Society of Core Analysts Technical production of various fluorine based chemicals, Achievement Award. He is a member of the intermediates, monomers and polymers. His National Academy of Engineers. experience covers a wide range of disciplines including research, process development, industrialization and business development. His current research interest is focused on various aspects of colloid and interface science, with specific reference to its application in the development of oilfield chemicals.

Emulsion Session Keynote Speaker

Dr. Jan Czarnecki got his M.Sc. in Theoretical and Ph.D. in Physical Chemistry, both from the Jagiellonian University in Krakow, Poland, and then a Doctor of Science degree in Colloid and Surface Science from the Institute of Physical Chemistry, Polish Academy of Sciences in Warsaw. He spent one year a post-doc fellow with Dr. Jan Leja at the Dept. of Mining and Mineral Process Eng., UBC in Vancouver. After close to 20 years at the Jagiellonian University, Jan became a Deputy Director of the Institute of Catalysis and Surface Chemistry, Polish Academy of Science in Krakow, Poland.

Jan and his family immigrated to Canada in 1987. Since 1988, Jan worked at Syncrude Research in Edmonton, Alberta, initially as Senior Associate, then Section Head, Team Leader and finally Senior Advisor. Jan retired from Syncrude Research in 2006. Currently Jan is an independent consultant working (with Drs. Jacob Masliyah and Zhenghe Xu) on “Handbook of Theory and Practice of Bitumen Extraction from Athabasca Oil Sands”. He is an adjunct professor at the Dept. of Chemical and Materials Eng, UofA in Edmonton, Alberta. He has over 110 scientific publications, about half of them on mineral processing and on surface and colloid chemistry in Canadian Oil Sands.

In 2000, Jan received a prestigious Alberta Science and Technology (ASTech) Prize for outstanding contributions to Oil Sands research.

8 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008 Tuesday, June 17 EMULSIONS Time Speaker Title AB # Could Naphthenic Acids be Responsible for 2:30 PM Vincent Pauchard Severe Emulsion Tightness for a Low TAN Value 18 Oil? Rupture of Interfacial Films at the Toluene-Water 3:00 PM Zhenghe Xu 19 Interface 3:30 PM Coffee Break The Formation of Rag Layers and the Role of 3:45PM Kevin Moran Interfacial Partition of Naphthenates and 20 Asphalthenes Effect of Film Area on Critical Electric Potential 4:15 PM Farshid Mostowfi 21 for O/W Emulsion Films Breakup Effect of Demulsifiers on Interfacial Films and 4:45 PM H.W. Yarranton Stability of Water-in-Oil Emulsions Stabilized by 22 Asphaltenes Dilational Rheology of Bitumen-Water Interfaces: 5:15 PM Alain Cagna Influence of Asphaltene Surfactants at Acidic and 23 Neutral pHs 5:45 PM Jan Czarnecki On Stabilization of Water in Crude Oil Emulsions 24 KEYNOTE

9 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Flow Assurance Session Co-Chairs

David Jennings is a Senior Jeff Creek received his Development Engineer with Bachelor of Science from Baker Petrolite in their Flow Middle Tennessee State Assurance Group. He has University in 1967, and his worked at Baker Petrolite for the Master of Science and Ph.D. last seven years involved in from Southern Illinois R&D and technical service University Carbondale in application work related to 1970 and 1976. chemical treatments for aiding petroleum production – especially with paraffin and asphaltene related issues. He worked with the Walter Reed Army Institute of Research from 1969 to 1971 and was a Post Prior to working for Baker Petrolite, David spent Doctoral Fellow – University of California in Los approximately eight years working at three different Angeles (UCLA) from 1975 to 1977. Following Exxon divisions: Exxon Production Research UCLA, he worked with Chevron Oil Field Research (working in Completion & Workover Group involved in and Chevron Technology Co., in La Habra from R&D/Technical Service work related to well 1977 to 1999.In 1999 he went to Chevron Texaco productivity, formation damage, & stimulation issues), Energy Technology Co. in Houston Texas where he Exxon Corporate Research (studying phase behavior acts as a Research Consultant with the Flow and deasphalting for Vapex Recovery Process for Assurance Team. bitumen), and Exxon R&D Laboratories (investigating supercritical fluid & separation applications for refinery processes).

He the author/co-author of several papers, presentations, and reports and has been involved in developing a number of commercial products for paraffin treatment.Before beginning his industrial career, David received a BS and PhD in Chemical Engineering from Clemson University and Georgia Institute of Technology, respectively. His dissertation

work was on high pressure phase equilibrium and supercritical fluid extraction.

Flow Assurance Session Keynote Speaker

Dr. Lloyd D. Brown (Doc) has worked in oil and gas, technology development for 18 years. His early work was in materials and corrosion. He transitioned into multiphase hydraulics while working the fundamentals of flow related corrosion in both sour and sweet fluids. His fundamental work in multiphase hydraulics led him into fluid phase behavior (vapor-liquid-aqueous-solids) and fluid mechanics interactions at production conditions. What we now call flow assurance. He has researched technologies and managed execution for the definition, simulation, and management of phase behavior, transport hydraulics, and deposition risk for wax, hydrates, corrosion, asphaltenes, and inorganic scales.

He specializes in real time research and development of technology details required for execution. He has worked with major projects and operations in successfully executing technology implementation and managing the discipline interfaces. Lloyd is now executing technology integration for flow assurance in concept selection and major projects. He presently manages advanced integrated simulation for ConocoPhillips in the Major Projects group located in Houston, Texas.

10 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008 Wednesday, June 18 Flow Assurance Time Speaker Title AB # Anticipating Flow Assurance Challenges Through 8:00 AM Matt Flannery 25 Geochemistry A Quartz Crystal Microbalance Characterization 8:30 AM Kristofer Paso of Metal-Oil Interfaces and Interactions with Wax 26 Molecules Dynamic Paraffin Deposition Experiments for Oil- 9:00 AM Cem Sarica Water Dispersions Created with South Pelto Oil 27 and Garden Banks Condensate Deposition from Wax-Solvent Mixtures under 9:30 AM Anil K. Mehrotra Turbulent Flow: Effects of Shear Rate and Time 28 on Deposit Properties 10:00 AM Coffee Break Rheology and FTIR Studies of Model Waxy 10:15 AM Milind D. Deo Crude Oils with Relevance to Gelled Pipeline 29 Restart Naphthenic Acid Extraction And Characterization Mohammed 10:45 AM From Crude Oils And Naphthenate Field 30 Murtala Ahmed Deposits Revisited. The Importance of Asphaltene Origin on its 11:15 AM Mark Grutters 31 Behaviour in Production Systems Flow Assurance: Complex Phase Behavior and 11:45 AM Lloyd Brown Complex Work Requires Confidence and 32 (KEYNOTE) Vigilance

11 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Upgrading and Refining Session Co-Chairs

Frans van den Berg graduated Paul Watkinson spent five years from the University of Leiden in industrial research before (majoring in Chemistry) and joining the faculty of the joined Shell in 1979. In 1983, Department of Chemical while working for Shell Research, Engineering at UBC in 1971, he obtained a PhD in the area of serving as Head of Department catalysis. from 1992 to 2001.

His main interest is the He has continued research in heat transfer, fouling, characterization and the utilization of heavy oils and and gasification as Professor Emeritus since 2004. residues. His initial studies were restricted to He is active in the Canadian Society for Chemical optimization of residu conversion processes. He was Engineering, and with Engineering Conferences involved in the development of the HYCON process International. He has published many papers related and of Shell Canada’s Oilsands Upgrading facilities. to particulate, precipitation and chemical reaction In 1996 he also became responsible for the research induced fouling, mainly in hydrocarbon systems, and and development on residual fuel products for marine has taught in numerous industrial short courses on and inland applications. In 2005 he was appointed fouling in Canada and abroad. In recent years his Principal Scientist Crude and Product Quality and research has dealt with fouling and coking of heavy became Technology Manager for Marine and oils and their products. Industrial Fuels. Frans and his team execute R&D for Shell companies and provide technical service and consultancy on heavy oil related subjects to both Shell companies and third parties. Asphaltene stability and product quality are some of the leading themes in his studies.

Upgrading and Refining Session Keynote Speaker

Dr. John M. Shaw, professor and NSERC Industrial Research Chair in Petroleum Thermodynamics, is a specialist in the phase behaviour of coal liquids, heavy oils and condensate rich reservoir fluids and the mixing/de-mixing issues related to such multiphase systems.

Dr. Shaw developed the x-ray view cell technology that permitted the first direct observation of the phase behaviour of opaque asphaltene-rich fluids. His work has attracted international attention and he has held visiting rofessorships at the Technical University of Delft (Netherlands), the Institut Francais du Petrole (France) and the Syncrude Research Centre. He has delivered invited lectures at numerous conferences, institutes, universities and private companies.

Dr. Shaw obtained his B.A. Sc. (1981) and PhD. (1985) at the University of British Columbia and served as professor in the Department of Chemical Engineering and Applied Chemistry at the University of Toronto before joining the University of Alberta in 2001.

12 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008 Thursday, June 19 Upgrading and Refining Time Speaker Title AB # Reactivity Modeling of the Visbreaking of William C. 8:00 AM Athabasca Bitumen Using Molecular 33 McCaffrey Representations Simon Ivar Measurement of Hydrogen Bonding Capacity of 8:30 AM 34 Andersen Heavy oil and Residues. A Platform for Techno-Economic Analysis of 9:00 AM E.M. Ishiyama Fouling Mitigation Options in Refinery Preheat 35 Trains. Characteristics of Heavy Vacuum Gas Oil 9:30 AM Paul Watkinson 36 Fouling in the Presence of Dissolved Oxygen 10:00 AM Coffee Break

Formation of Asphaltene Deposits From Crude 10:15 AM Jianxin Wang 37 Oil Destabilized by Addition of Propane

Recovery of Lighter Fuels by Cracking Heavy Oil 10:45 AM Eri Fumoto With Zirconia-Supporting Iron Oxide Catalyst in a 38 Steam Atmosphere 11:45 AM John M. Shaw Complex Phase Behaviour in Bitumen Upgrading 39 (KEYNOTE)

13 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

POSTER SESSION I - MONDAY, JUNE 16, 6:00 - 9:00 PM Board AB Presentation Title Submitted by # # Time Study of the Gelation Behaviour of 6:00 & 7:00 M1 Claudio Ziglio 40 Brazilian Waxy Crude Oils PM Cold Flow' Deposition Experiments With 6:15 & 7:15 M2 Wax-Solvent Mixtures Under Laminar Flow Anil K. Mehrotra 41 PM in a Flow-Loop with Heat Transfer Comparison and Structural Elucidation of Naphthenic Acids Found in Sodium and Calcium Naphthenate Deposits by 6:30 & 7:30 M3 Andrew Yen 42 Electrospray Ionization Fourier Transform PM Ion Cyclotron Resonance Mass Spectrometry Compari son of Crude Oil Interfacial 6:45 & 7:45 M4 Jannie Beetge 43 Behavior PM

Physical and Chemical Properties of Deasphalted Oil and Asphaltenes from 6:00 & 7:00 M5 David Jennings 44 Laboratory Deasphalting Experiments on PM Alberta Bitumen A Bulk Rheological Investigation of Crude 6:15 & 7:15 M6 Geoff Robinson 45 Oils from Various Sources PM Phase Behavior and Physical Properties of 6:30 & 7:30 M7 Harvey Yarranton 46 Athabasca Bitumen, Propane, and CO2 PM Liquid - Solid Phase Equilibrium of 6:45 & 7:45 M8 Tetradecane + Dodecyl-Cyclohexane Jean Luc Daridon 47 PM System Under Pressure. Further Adventures in Binding Resins: 6:00 & 7:00 M9 Investigations into Asphaltene - Binding Brendan Graham 48 PM Resin Interaction Asph altene Equilibrium in Oil Columns with 6:15 & 7:15 M10 Denise Freed 49 Varying GOR PM Interaction Between Asphaltenes and 6:30 & 7:30 M11 Peter Siedl 50 Minerals in Asphalt Mixtures PM Interfacial Tension Change Due to 6:45 & 7:45 M12 Asphaltene Flocculation in Recombined Hervé Carrier 51 PM Oils Sedimentation of Asphaltenes Dissolved in 6:00 & 7:00 M13 Toluene Using Ultracentrifugation Farshid Mostowfi 52 PM Technique Study of Asphaltenes Aggregation by 6:15 & 7:15 M14 Héctor Gutiérrez 53 Dynamic Light Scattering PM

Characterization of the Onset Asphaltenes 6:30 & 7:30 M15 Raul Gimenez 54 by Focused-Beam Laser Reflectance: A PM Tool for Chemical Additives Screening

Inorganic Solid Content Continues to 6:45 & 7:45 M16 Michael Poindexter 55 Govern Water-in-Crude Oil Emulsion PM Stability Predictions

14 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

POSTER SESSION I - MONDAY, JUNE 16, 6:00 - 9:00 PM Board AB Presentation Title Submitted by # # Time An Investigation of Emulsion Interfacial 6:00 & 7:00 M17 Material by Ultrahigh Resolution FT-ICR Brandie Ehrmann 56 PM Mass Spectrometry Estimation of the Size of Asphaltene 6:15 & 7:15 M18 Aggregates Produced by Shear of Crude Lech Gmachowski 57 PM Oil Wax Deposition Measurement Under Kamran 6:30 & 7:30 M19 Turbulent Flow Conditions for a Live Waxy 58 Akbarzadeh PM Crude From Turkmenistan 6:45 & 7:45 M20 The Effect of Fluid Shearing and Wax Tony Moorwood 59 Ageing on Wax Deposition in Pipelines PM

Analysis of Acidic Compound Classes in Crude Oil by Negative Ion Electrospray 6:00 & 7:00 M21 Priyanka Juyal 60 Ionization High Resolution FT-ICR Mass PM Spectrometry Quantitative Molecular Representation of 6:15 & 7:15 M22 Asphaltenes and Molecular Dynamics Tom Headon 61 PM Simulation of Asphaltene Aggregation Could Naphthenic Acids be Responsible for Severe Emulsion Tightness for a Low 6:30 & 7:30 M23 Vincent Pauchard 62 TAN Value Oil? Part 1: Position of the PM Problem. Systematic Study of Crude Oil-Rock-Clay 6:45 & 7:45 M24 Interactions Using a Quartz Crystal Lamia Goual 63 PM Microbalance Investigation on the Influence of 6:00 & 7:00 M25 Surfactants on the Wax Appearance Tereza Dantas 64 PM Temperature through Rheological Assays X -ray Photoelectron Spectroscopy and 6:15 & 7:15 M26 ToF-SIMS Analysis of Asphaltene Wa'el Abdallah 65 PM Adsorption on Metallic Surfaces Charge Dependent Asphaltene Adsorption 6:00 & 7:00 M27 onto Metal Substrate: Electrochemistry Nikola Batina 66 PM and AFM, STM, SAM, SEM Analysis Adsorption of Petroleum Resins and Asphaltenes onto Reservoir Rock Sands Rustem Z. 6:15 & 7:15 M28 67 Studied by Near Infrared (NIR) Syunyaev PM Spectroscopy Electrospray Ionization FT-ICR Mass Spectrometry of 'ARN' Naphthenic Acids in 6:30 & 7:30 M29 Myles Mapolelo 68 Crudes: Preconcentration and PM Quantification

Effect Of Salts on the Interfacial Tension of 6:45 & 7:45 M30 Asphaltene-Toulene/Water Interface: Rogério Sé 69 Prediction by Poisson-Boltzmann Modified PM Model and Experimental Validation

15 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

POSTER SESSION II - WEDNESDAY, JUNE 18, 6:00 - 9:00 PM Board AB Presentation Title Submitted by # # Time Atmospheric Pressure Photoionization Fourier Transform Ion Cyclotron 6:00 & 7:00 W1 Resonance Mass Spectrometry for Amy McKenna 70 PM Detailed Compositional Analysis of Petroleum Asphaltenes: Interfacial Aggregates: 6:15 & 7:15 W2 Gabriela Alvarez 71 Characterization and Film Structure PM Observations on Silicate and pH Control to Improve Separation of Water-in-Diluted 6:30 & 7:30 W3 Tianmin Jiang 72 Bitumen Emulsions Containing Clay PM Solids Asphaltene Inhibitor Squeezing - What 6:45 & 7:45 W4 Can We Learn From Scale Inhibitor Keith Allan 73 PM Squeezing? 6:00 & 7:00 W5 Flow Assurance Oliver Mullins 74 PM Characteristics of Wax Gel Formation in 6:15 & 7:15 W6 Kyeongseok Oh 75 the Presence of Asphaltenes PM Assessment of Different Models to 6:30 & 7:30 W7 Describe Wax Precipitation in Flow M. Dolores Robustillo 76 PM Assurance Problems Comparison of Crude Oils by Intrinsic 6:45 & 7:45 W8 Jannie Beetge 77 Viscosity Studies in Different Solvents PM Role of Resins, Asphaltenes and 6:00 & 7:00 W9 Chris Jones 78 Aromatics on Water-Oil Emulsions PM Dipole Moment of Asphaltene 6:15 & 7:15 W10 Rustem Z. Syunyaev 79 Nanoclusters PM The Distribution of Polar Species in 6:30 & 7:30 W11 Sara Salmon 80 Athabasca Asphaltenes PM

Interface Behavior of Crudo Oil/Gas Douglas J Escalante 6:45 & 7:45 W12 Systems in Function of Pressure and 81 Ayala PM Temperature The Distribution of Polycyclic Aromatic Yosadara Ruiz- 6:00 & 7:00 W13 82 Hydrocarbons in Asphaltenes Morales PM Implications of Colloidal Phase Transitions 6:15 & 7:15 W14 Geza Horvath-Szabo 83 on Reservoir Compartmentalization PM Thermal lens Technique to Evaluate the 6:30 & 7:30 W15 Fluorescence Quantum Yield of Manuel Caetano 84 PM Asphaltene Solutions Modelling Asphaltene Precipitation 6:45 & 7:45 W16 Equilibrium: Influence of the Experimental Raul Gimenez 85 PM Contact Time and Temperature

Modelling the Effect of Gas Injections on 6:00 & 7:00 W17 the Stability of Asphaltene-Containing Tony Moorwood 86 PM Crude Oils

16 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

POSTER SESSION II - WEDNESDAY, JUNE 18, 6:00 - 9:00 PM Presentation Board # Title Submitted by AB # Time Formation and Aging of Deposits from Coker W18 Zhiming Fan 87 6:15 & 7:15 PM Vapours Rheological Study of Athabasca Bitumen and W19 John M. Shaw 88 6:30 & 7:30 PM Maya Crude Oil Solution Behavior of Naphthenic Acids and W20 its Effect on the Asphaltenes Precipitation Gaspar González 89 6:45 & 7:45 PM Onset. Control of Hydrolysis of Emulsified Salts in W21 Murray Gray 90 6:00 & 7:00 PM Canadian Bitumens A QCM technique to Quantify the Gas W22 Jérôme Pauly 91 6:15 & 7:15 PM Solubilization in Oil

Evaluation of Hydrotreating Reaction Time of W23 Furrial Crude Oil for Improvement of Miguel A. Luis 92 6:30 & 7:30 PM Asphaltene and Their Fractions in p- Nitrophenol Inves tigation of Heavy Petroleum Oils from Maria Helena G. W24 Different Refineries by Group-Class 93 6:45 & 7:45 PM Pereira Characterization Could Naphthenic Acids be Responsible for W25 Severe Emulsion Tightness for a Low TAN Vincent Pauchard 94 6:00 & 7:00 PM Value Oil? Part 2: Interfacial Rheology. Could Naphthenic Acids be Responsible for W26 Severe Emulsion Tightness for a Low TAN Vincent Pauchard 95 6:15 & 7:15 PM Value Oil? Part 3: Analytical Chemistry.

Colloidal Analysis of the Asphaltene and Their Fractions With p-Nitrophenol (PNP) of Henry Labrador- W27 96 6:00 & 7:00 PM the Furrial Crude Oil for Effect of the Sánchez Hydrotreating to Different Pressures Equivalent Alkane Carbon Number (EACN) W28 of Oils and Solvents and Characteristic Edgar Acosta 97 6:15 & 7:15 PM Curvature of Naphthenic Compounds.

Application of Microemulsion Systems in the W29 Tereza Dantas 98 6:30 & 7:30 PM Desorption of Heavy Petroleum Fractions

X -Ray Diffraction of Asphaltenes Heptol Sub- W30 Lina Constanza 99 6:45 & 7:45 PM Fractions From a Brazilian Vacuum Residue The Effect of Fluid Shearing and Wax Ageing W31 Daniel Merino Garcia 100 6:30 & 7:30 PM on Was Deposition in Pipelines

17 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

18 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 1

A Method for the Prediction of Boiling Point Curve of Heavy-Hydrocarbon Residua Based on Solubility Data

P. Peczak and H. Freund

Corporate Strategic Research, EMRE

The normal boiling point (BP) is a critical descriptor of crude oil quality. Just as the specific gravity (SG), this continuous property of petroleum is used in refineries as a controlling parameter in their fractionation into various distillation cuts. Over the last 50 years, researchers have been proposing correlation between BP and other molecular parameters, e.g., the molecular weight, SG, the H/C ratio, or the refractive index. The importance of these models cannot be overestimated as they are used to predict both the refining product yield distribution and quality.

As it is particularly difficult to measure boiling points for high molecular weight materials, we propose a novel technique that allows one to estimate the boiling point - molecular weight relationship using solubility parameter data, particularly for heavy-oil fractions.

To test the method, we have chosen a compositional model of petroleum modeled with representative hydrocarbon molecules, the selection and relative abundance of which was correlated to the ensamble-averaged properties of a few hypothetical crude oils. By applying well-established correlations between the boiling point and the critical properties and the acentric factor, we have estimated the solubility parameter data for the molecules using the equation-of-state approach. We have compared these solubility parameter data with those calculated using a classical group contribution method. Our results suggest a systematic deviation between the two data set as the molecular weight of the molecules increases above about 600 amu.

The results strongly suggest that either the boiling point curves assumed for the highmolecular- weight components by several published models are incorrect or the group contribution method does not reliably estimate the solubility parameter data for these components.

19 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 2

Phase Behaviour of Heavy Oils and Bitumen – an Approach Based on Calorimetry and Rheology

Michal Fulem1,2, Mildred Becerra1 and John M. Shaw1

1 Department of Chemical and Materials Engineering, University of Alberta, Edmonton, Alberta, T6G 2G6, Canada. 2 Institute of Physics, Academy of Sciences of the Czech Republic, v. v. i., Cukrovarnická 10, CZ-162 53 Prague 6, Czech Republic.

The phase behavior of heavy oils and bitumen is key to the success of process development, process design, and process operation activities related to them. These materials, like many other fluids of industrial interest, are opaque to visible light, and are not amenable to investigation using conventional view cell technologies or even x-ray transmission tomography [1], and a combination of techniques is required to elucidate their phase behavior. Differential scanning calorimetry (DSC) is a sensitive technique for the detection and evaluation of phase transitions. In addition, temperature modulated DSC (TMDSC) is capable of distinguishing between reversible and irreversible phase transitions. However, in the case of complex materials like heavy oils or bitumen it is often difficult to interpret observed phase transitions, i.e. to determine the nature of the initial and final phase states. Rheological analysis identifies the nature of phase transitions detected by DSC or TMDSC since it sheds light on phase states. In this contribution, we present a combined calorimetric and rheological study of Maya crude oil and Athabasca bitumen which, in connection with the results obtained by solvent-free nanofitration [2] and a predictive heat capacity correlation for solids developed in our research group [3], reveals key phase behaviors for these ill-defined hydrocarbons. Preliminary phase diagrams for Maya crude oil and Athabasca bitumen are presented.

References [1] S.J. Abedi, H.-Y. Cai, S. Seyfaie, J.M. Shaw Fluid Phase Equilib. 158 (1999) 775–781. [2] B. Zhao, B., J.M. Shaw Energy & Fuels 21 (2007) 2795-2804. [3] V. Laštovka, V., J.M. Shaw, J. Chem. Eng. Data 52 (2007) 1160-116

20 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 3

Isothermal Pressure Effect on Asphaltene Phase Behaviour

E.A. Chukwudeme, A.A. Hamouda

Department of Petroleum Engineering, University of Stavanger, 4036 Stavanger, Norway

An approach to address the effect of pressure drop on aphaltene precipitation under isothermal conditions is presented. In this work extracted asphaltene from crude oil is dissolved in model oil (artificial/model oil, with known composition).

Various models are proposed in literature to determine the onset of asphaltene precipitation. These models account for the effect of pressure, temperature and CO2. Phase behaviour of model oil and CO2 flooding has been addressed in our previous work. A simple relationship between injected CO2 and phase behaviour on the asphaltene precipitation in flooded asphaltenic oil with CO2 largely affect asphaltene phase separation compared to that in absence of CO2.

In this work, it is demonstrated that pressure drop play dominant role on asphaltene precipitation. Phase behaviour of model oil as well as crude oil from selected fields are presented. Also, viscosity of model oil containing asphaltene with concentrations of 0.26 wt %, 0.36 wt %, 0.56wt % and 1.1 wt % is investigated with respect to its effect on mobility.

21 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 4

Application of the PC-SAFT EoS in the Definition of a Universal Plot for Asphaltene Stability

F. Vargas1, D. Gonzalez1,2, J. Wang3, J. Creek3, J. Buckley4, G. Hirasaki1 and W. Chapman1

1Chemical and Biomolecular Engineering Department, Rice University, Houston, Tx, USA 2Schlumberger, Houston, Tx, USA, 3Chevron Energy Technology Company, Houston, Tx, USA 4 PRRC, New Mexico Tech, Socorro, NM, USA

Asphaltenes constitute a potential problem in deep water production because of its tendency to precipitate and deposit. The knowledge that we have so far about asphaltenes is limited. Although many efforts have been made to elucidate the nature and behavior of asphaltenes, the mechanisms of aggregation and deposition are not completely understood. Additionally, most of the time, the relationships that are proposed between ambient condition data and reservoir precipitation onsets are specific for each crude oil and depend on the procedure used to perform the measurements. A universal model to predict the stability of these species, under different conditions, is desirable in order to identify potential asphaltene problems. This approach has been previously followed by de Boer. This first attempt to develop a universal plot for asphaltene stability was based on the Flory-Huggins theory (FHT) with the assumption of a crude oil saturated with asphaltenes at reservoir conditions. The de Boer method has been widely used in oil industry to forecast asphaltene problems. However, this model produces false positives. Alternatively to the FHT, the PC-SAFT Equation of State (EoS) has been successfully applied in modeling asphaltene stability.

In our study, we present important advances in developing a general method to model asphaltene stability in oil, using the PC-SAFT EoS, regardless of the oil components and their compositions. By defining dimensionless parameters, the equilibrium curves of different multicomponent mixtures collapse onto one single curve. Universal plots for the bubble point and the onset of asphaltene precipitation have been obtained, which are in excellent agreement with results obtained from simulations.

Extension of this model to mixtures containing dissolved gases, such as methane, CO2 and ethane, is also included. This part of the study led to questions regarding the validity of the current mixing rule for solubility parameters of mixtures containing dissolved gases. It is well known, that the geometric mean for intermolecular forces of different species, assumed by the Regular Solution theory (RST) and, consequently, by the FHT, becomes increasingly poor as the difference in size between molecules increases. However, current methods ignore this limitation and, in practice, utilize correction factors to match the gas solubility data. In the present work we show a derivation of a new mixing rule for solubility parameters of mixtures containing liquids and dissolved gases. The agreement with simulation results and refractive index measurements is good. Furthermore, the universal curves for asphaltene stability and the corresponding dimensionless numbers proposed in this study can be readily obtained by applying this new mixing rule. Results obtained in this work are very promising in providing new tools to model asphaltene stability under reservoir conditions.

22 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 5

Modeling and Prediction of Non-Newtonian Viscosity of Crude Oils

Patsy V. Ramírez-González 1, Sergio E. Quiñones-Cisneros 2, Octavio Manero 2, Jefferson Creek 3 and Ulrich K. Deiters 4

1 Facultad de Química, Departamento de Ingeniería Química, Universidad Nacional Autónoma de México, 04510, México D.F., Mexico 2 Departamento de Reología, Instituto de Investigaciones en Materiales, Universidad Nacional Autónoma de México, Apdo. Postal 70-360 México, D.F. 04510, Mexico 3 Chevron Energy Technology Company, 1600 Smith St., 30058B, Houston, TX 77002, U.S.A., 4 University of Cologne, Institute of Physical Chemistry, Luxemburger Str. 116, D-50939 Cologne, Germany.

The presence of precipitated wax in reservoir fluids or even just low (ambient) temperatures in heavy oils may induce non-Newtonian rheological behavior in crude oils. Such behavior can easily be found at operating conditions; for instance, due to the low- temperatures encountered at deep-water conditions or in the case of vapor extraction (VAPEX) processes of heavy oils involving strong compositional related changes to the already non-Newtonian viscosity of the oil. Therefore, reliable rheological models for crude oils applicable over the wide range of conditions the fluid may encounter is key for a large number of oil technology applications. Such models must also be of a compositional nature as many applications require predicting the rheological behavior of the fluid under strong compositional changes, e.g. recovery applications such as VAPEX processes or blending of fluids for improved rheological characteristics for piping, between many other applications.

In this work, a comparative study between some published models applicable for the description of the non-Newtonian behavior of crude oils is carried out. Emphasis is to be made regarding the stability of the models predictions within the wide range of conditions that may be encountered. An evaluation of the prediction potential of the analyzed models will also be presented.

23 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 6

Rheological Characterization Under Pressure of Foamy Oils and Live Heavy Oil Emulsions

P. Abivin, I. Hénaut, C. Chaudemanche, J.-F. Argillier

IFP, 1 & 4 avenue de Bois-Préau, F-92852 Rueil-Malmaison

Besides their very high viscosity, another characteristics of heavy crude oils is their tendency to form very stable foams and emulsions. These dispersed systems are encountered during different exploitation phases and in different locations (reservoirs, wells, surface equipment). Understanding and modeling of the rheological behavior under application conditions (pressure, temperature) of foamy oils (gas bubbles embedded inside heavy crude oil matrix) and live heavy oil emulsions (water in oil or oil in water) is a key issue to optimize processing operations. Only few studies are related to such characterizations. This study is an extent of our previous works dedicated on foamy oils and water-in-oil emulsions and will depict more accurately the behavior under pressure of real multiphase systems.

Rheological characterization under pressure of foamy oils, water-in-oil emulsions and live water-in-oil emulsions are carried out using a controlled stress rheometer equipped with a pressure cell. The advantage of such a rheometer is the capacity to dissolve and produce gas bubbles with a continuous monitoring of the viscosity, pressure, temperature and shear rate. Therefore, this original approach allows us to study the pressure-dependence of the heavy oil viscosity and its changes with the presence and size of water droplets and gas bubbles. Finally, among all the physical-chemical and processing parameters, a particular focus is given to the depletion rate and the shear rate and their effect on flow properties is discussed.

24 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 7

Modeling Asphaltene Phase Behavior in Crude Oil Systems

Francisco M. Vargas, Doris L. Gonzalez, George J. Hirasaki, Walter G. Chapman Rice University, Houston, TX, USA

Asphaltene precipitation and deposition can occur at different stages during petroleum production causing reservoir formation damage and plugging of pipeline and production equipment. Predicting asphaltene flow assurance issues requires the ability to model phase behavior of asphaltenes as a function of temperature, pressure, and composition. In this presentation, we review some recent approaches to model asphaltene phase behavior. We also present a method to characterize crude oil including asphaltenes using the perturbed chain form of the Statistical Associating Fluid Theory (PC-SAFT). The theory accurately predicts crude oil bubble point and density as well as asphaltene precipitation conditions. The theory is used to examine the effects of gas injection, commingling of reservoir fluids, and asphaltene polydispersity on the phase behavior of asphaltenes. The analysis produces some interesting insights into field and laboratory observations of asphaltene phase behavior.

25 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 8

Investigations on Asphaltenes Precipitate Properties

Valérie Montel1,2, Véronique Lazzeri2, Grégoire Porte3 , Jacques Jestin4 Honggang Zhou1

1Total, CSTJF, Avenue Larribau, 64018 Pau Cedex, France. 2Université de Pau et des Pays de l’Adour, LTEFC UMR 5150, BP1155, 64013 Pau Cedex, France, 3LCVN/CNRS Case 026, Université Montpellier II, 34095 Montpellier Cedex 05, France, 4Laboratoire /pon Brillouin CEA/CNRS, CEA Saclay, 91191 Gif sur Yvette, France

Asphaltenes deposition may occur anywhere in the oil production system ultimately reducing the well productivity. The aim of this work is to identify the relevant parameters controlling the damaging potential of asphaltenes deposits. Our approach is to dissociate the deposit from the porous rock matrix in order to define accurate parameters which control the deposit behavior . To this end, a filtration process have been developed for the characterisation of asphaltenes cake properties. First experiments conducted on a venezuelian crude oil indicates that asphaltenes cakes shows properties similar to those of clay or sludge. The absolute porosity of asphaltenes cakes is important, around 88%, while apparent permeabilities are low, from 10µD to 100µD. With increasing pressure, the absolute porosities remains roughly constant whereas the apparent permeabilities decreases strongly. This intriguing apparent contradiction suggests that the porosity, which effectively contributes to the permeation flow, corresponds only to a small portion of the total porosity of the deposit. One possibility is that most of the total porosity is in fact occluded and therefore cannot contribute to the flow. In order to check this point we have used small angle neutrons scattering.

Neutron scattering has been extensively used to investigate the self assembling properties of asphaltenes solutions in apolar solvents. It was clearly demonstrated that asphaltene in solution spontaneously forms nanoaggregates of typical size 5 to 10 nanometers and apparent molecular weight of the order of 50 000 to 100 000 g/mol. On the other hand, neutron scattering has not been used to date to investigate the porous nanostructure of the solid asphaltene precipitate. As far as finely divided materials are concerned, neutron scattering can provide interesting caracteristics of the porosity: size and polydispersity of the pores, area of interface per unit volume of the materials. Evenmore using contrast variation, it is in principle possible to separate the open versus occluded porosity. In the present work, we have precipated asphaltene in a large excess of hydrogenated heptane. We then rinced the precipitate obtained in a mixture of hydrogenated and deuterated heptane which cancels the contrast with the asphaltene. In such conditions, the open porosity exhibits no contrast wheras the occluded one which is still filled with pure h-heptane, alone contributes to the total scattering.

26 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 9

Nanocolloidal Dispersion of Asphaltenes in (Reservoir) Crude Oil

Oliver C. Mullins1, Soraya S. Betancourt1, G. Todd Ventura2, Oswaldo Viloria3, Francois X. Dubost1, Drew Pomerantz1, Jerry M. Purcell4, Robert K. Nelson2, Ryan P. Rodgers4, Christopher M. Reddy2, Alan G. Marshall4

1Schlumberger-Doll Research, 2Woods Hole Oceanographic Institute, 3Pioneer Natural Resources USA, Inc. 4Florida State University

The nature of the dispersion of asphaltenes in toluene and crude oil has been of long standing interest. SAXS and SANS results on asphaltenes always show nanocolloidal structures amongst other length scales. High-Q ultrasonics indicate very low concentrations of nanoaggregate formation in toluene and NMR diffusion experiments established there are ~8 molecules per nanoaggregate. Most recently, asphaltenes were shown to exist in reservoir (black) crude oils as ~2 nm colloidal particles. In this study, a second reservoir black oil is analyzed from a different field and confirmation is found that asphaltenes exist as 2 nm colloidal particles. Moreover, detailed chemical analyses of the crude oils and contained asphaltenes reinforce the primary foundation of the analysis – that this black oil exists in the reservoir in an equilibrium condition. Two dimensional gas chromatography shows that the liquid phase of the oils are the same with respect to various fluid metrics such as their biomarkers. In addition, ESI FT-ICR mass spectroscopy is used to provide probe the polar components of the oils. Again, the chemistry is found to be invariant. Moreover, elsewhere in the reservoir where lack of connectivity is indicated, the fluids are grossly different. The conclusions from this study match previous field and lab results, asphaltenes are nanocolloidally suspended in crude oils. This observation is shown to be important in addressing reservoir architecture.

27 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 10

Asphaltene-Resin Association

Eric Sirota and Pawel Peczak

Corporate Strategic Research, ExxonMobil Research and Engineering Company

The association of resins with asphaltenes (or lack thereof) is a phenomenon which is getting recent renewed attention. Discussion of such association, however, is often carried out within the context of the picture of asphaltenes-as-colloidal-aggregates being peptized by surfactant-like resin species.

What do we mean by "associated "? To some it means attached almost permanently. But it also means: "can be found as a neighbor more often than not". The cartoons based on the Yen picture suggest that a "resin-peptized asphaltene aggregate" will be bigger (including both resin and asphaltene), due to the additional size of the resin. However scattering results show that this is not the case. Is this because resins don't associate with asphaltenes? Or is the picture of fundamental asphaltene aggregates incorrect? The observations are consistent with the resins competitively associating with the asphaltenes, limiting the asphaltene-asphaltene association, and reducing the average extent (correlation length) of asphaltene/resin clustering. When we talk about such association, do we mean that the resins associate to keeps asphaltenes in a single phase liquid when they otherwise would phase separate? And/or are the resins associated so that they co-precipitate with the asphaltenes? But then would they not be asphaltenes, by definition?

Do asphaltenes and resins form a continuum? Maybe we should define what we mean by "resins". Some studies define the heptane precipitates as the asphaltenes, and the pentane insolubles from the heptane deasphalted oil as the "resins" (pentane resins). Others extract heptane asphaltenes and use an adsorbent to extract "resins". Clearly the latter would never be expected to form a continuum with the asphaltenes because of the totally different method of preparation. The pentane resins clearly must form a continuum, as one can continuously slide the definition of resins and asphaltenes just by choice of solvent and solvent mixtures. We will present both solubility/phase behavior data as well as scattering results to clarify the above questions. We then will show how this behavior is explained by considering the local composition in a solution of complex molecules.

28 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 11

Kinetics of Asphaltene Precipitation from Crude Oils

Tabish Maqbool, Iman A. Hussein and H. Scott Fogler

Department of Chemical Engineering, University of Michigan, Ann Arbor

This research investigates the kinetics of asphaltene precipitation from crude oils using n-alkane precipitants. Conventionally, it has been understood that the precipitation of asphaltenes is governed by the amount of precipitant added to the crude oil [1,2]. Recent literature shows that there is a kinetic phenomenon associated with asphaltene precipitation [3]. In this research we have demonstrated that depending upon the amount of n-alkane precipitant added, the time required to precipitate the asphaltenes may vary from a few minutes to several months. Therefore, the onset of asphaltene precipitation is a function of the concentration of precipitant and time. A technique to quantify the amount of asphaltenes precipitated as a function of time and precipitant concentration is also discussed. The kinetic effects caused by various precipitants have been also investigated in this work. The growth of asphaltene aggregates was monitored with time using optical microscopy. Refractive index measurements were that were made, provided further insight into the kinetics of asphaltene precipitation. In order to compare the nature of asphaltenes precipitated early in the precipitation process to the asphaltenes precipitated at later times, polarity based fractionation and dielectric constant measurements were used. Results from these experiments show that the asphaltenes precipitating at different times from the same crude oil-precipitant mixture are different from each other.

[1] P. Wattana, D.J. Wojciechowski, G. Bolaños, H.S. Fogler, Petroleum Science and Technology, 2003, 21, 3-4, 591 - 613 [2] A. Pina, P. Mougin and E. Béhar, Oil & Gas Science and Technology – Rev. IFP, 2006, 61, 3, 319-343 [3] C.W. Angle, Y. Long, H. Hamza and L. Lue, Fuel, 2006, 85, 4, 492-506

29 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 12

Understand the Intriguing Solubility Properties of Asphaltenes in Apolar Solvents

Honggang Zhou1, Grégoire Porte2, Véronique LazzeriI3, Valérie Montel1

1Total, CSTJF, Avenue Larribau, 64018 Pau Cedex France 2LCVN/CNRS Case 026, Université Montpellier II, 34095 Montpellier Cedex 05, France 3Université de Pau et des Pays de l’Adour, LTEFC UMR 5150, BP1155, Pau Cedex, France

Asphaltenes precipitation often has catastrophic impact on oil production and transportation. Yet, their quite unique solubility properties in apolar solvent remain to date poorly understood. The precipitation threshold appears remarkably insensitive to the degree of dilution. Moreover, resins, which are usually considered as more soluble asphaltene fractions, have strong cosolubilising power on the most insoluble asphaltene fractions. Some topics are still controversial such as asphaltene molecular weight, critical concentration of nano-aggregation, size of nano aggregates and role of resins... In this work, some new experiments are presented to illustrate further these issues.

In this presentation, a very simple new thermodynamic description of the asphaltene fraction is explained. Our purpose here is not to add one more thermodynamic model pretending to predict accurately the asphaltene precipitation, but rather to build up a consistent qualitative explanation of major intriguing properties of asphaltenes. In our interpretation, asphaltene in good solvents always self-assemble in finite size nano- aggregates due to strong specific attractive interactions. Precipitation then occurs when shifting down the quality of the oil solvent due to non-specific dispersion forces. Within this picture, the ultra low sensitivity to dilution, the cosolubilising effects and the effect of fractionation on the precipitation thresholds are easily understood.

A new classification protocol (Asphaltene Solubility Class Index or ASCI) is presented to characterize the overall asphaltene solubility properties. Examples are presented where the new description and the new protocol help to understand and resolve practical field problems.

30 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 13

SANS Experiments and Molecular Dynamics Studies of Asphaltenes: Driving Force and Morphology of Nano-Aggregation

T. F. Headen1, N. T. Skipper1, E. S. Boek2

1Dept. Physics and Astronomy, University College London, Gower Street, London UK 2Schlumberger Cambridge Research, High Cross, Madingley Road, Cambridge

It is well established from small-angle scattering experiments that asphaltenes form nanoaggregates of radius 30-70Å. However, the shape of the nanoaggregate, the arrangement of the asphaltene molecules in the nanoaggregates and the driving force behind its formation are still not well understood. The aim of this work is to use SANS experiments to probe the shape of the asphaltene nanoaggregates in toluene solution and crude oil. In addition, Molecular Dynamics (MD) simulations of model asphaltene structures will be used to discover the most probable morphology of asphaltene molecules in nanoaggregates (equilibrium distance, angle between aromatic planes etc.) and the nature and strength of the driving force behind aggregation (free energy, enthalpy and entropy).

SANS experiments have been conducted on heptane extracted asphaltenes in d8- toluene and on a crude oil [1]. Shape independent Guinier analysis shows similar radii of gyration, and similar size variation with temperature in solution and crude. Fitting of the SANS data to geometric form factors showed that a rod geometry with R˜15Å and L=150Å gave the best fit in d8-toluene and crude. In addition V-SANS experiments were conducted on the crude oil. This allowed access to the very low Q Guinier plateau of the larger asphaltene aggregate, giving R=0.47?m. Combined SANS and V-SANS has shown that the large scale aggregates are not simply made from building blocks of smaller nanoaggregates. Instead, they are two different aggregates coexisting.

Molecular Dynamics simulations have been conducted on three asphaltene structures obtained using the Quantitative Molecular Representation (QMR) method [2]. These structures are representative of asphaltenes extracted from a crude oil and are consistent with experimental measurements (NMR, elemental analysis). Potential of Mean Force (PMF) calculations between pairs asphaltene molecules were conducted in baths of explicit solvent molecules, both toluene and heptane. The results showed larger equilibrium distances between the molecules (5 – 7 Å) than the ??– ??stacking distance seen in solid asphaltene (3.7 Å), indicating “looser” aggregation in asphaltene nanoaggregates. Integration of the PMF curves gives an estimate of the free energy as a function of distance between the aggregates. From this we find that the free energy of aggregation is approximately -8 kJ mol-1. Interestingly there is little difference between the PMF curves in toluene and heptane, indicating that the nano-aggregation process is relatively independent of solvent. This implies that it is larger scale aggregation seen in the V-SANS experiments that occurs in heptane and does not occur in toluene. Larger simulations have also been conducted for six asphaltene molecules in a box of solvent at 7wt% asphaltene. Initial results show that aggregation does occur spontaneously. Further analysis of the simulations to give the most probable morphology of asphaltene aggregates is still ongoing.

[1] T. F. Headen, U. Scheven, J. Stellbrink, E.S. Boek. Article in preparation (2008). [2] E.S. Boek, T. Headen, D. Yakovlev. Article in preparation (2008).

31 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 14

Investigation of the Effects of Water on Aggregation of Model Asphaltenes in Organic Solution

Xiaoli Tan1, Hicham Fenniri2, Murray R. Gray1

1Department of Chemical and Materials Engineering, University of Alberta, Edmonton, Alberta, T6G 2G6, Canada 2Department of Chemistry and National Institute for Nanotechnology, University of Alberta, Edmonton, Alberta, T6G 2M9, Canada

Recently studies by isothermal titration calorimetry1 and molecular mechanics calculations2 suggested the presence of traces of water in solvents had significant effects on the aggregation behavior of asphaltenes. The suggested interaction mechanism is that water forms bridging H bonds between some of the heteroatoms of the asphaltenes in solution. These results gave insight into the aggregation behavior of asphaltenes, however, the results were qualitative due to the complex mixture properties of asphaltenes. Our previous studies on 4,4’-bis-(2-pyren-1-yl-ethyl)-[2,2’]bipyridinyl (abb. PBP)3 showed that PBP is an archipelago model compound that mimics some of the physical behavior of asphaltenes. These results prompted us to study the interaction of water and PBP in solution in order to obtain quantitative information on molecular interactions that may be important in the aggregation of actual asphaltenes. In this presentation, the interaction of PBP and water at trace concentrations was studied using concentration-dependent 1H NMR and temperature-dependent 1H NMR experiments. The concentration-dependent 1H NMR results showed that trace water (ranging from 0.42 to 0.84 mg/mL) was favorable to the aggregation of PBP; the variable-temperature 1H NMR results showed the temperature coefficients of proton for PBP (ppm.K-1) is larger in water containing chloroform-d than in dry chloroform-d. These results suggested the water probably forms bridging H bonds between the nitrogen atoms of PBP to induce the aggregation of PBP at low concentrations. On the basis of these studies, the thermodynamic parameters were determined. These studies provided further understanding of asphaltene self-association, flocculation, and deposition in the oil industry.

References:

1. Andersen, S.I. Langmuir 2001, 17, 307-313. 2. Murgich, J.; Merino-Garcia D.; Andersen S. I.; del Rio, J. M.; Galeana, C. L. Langmuir 2002, 18, 9080-9086. 3. Tan, X. L.; Fenniri, H.; Gray, M. R. Energy & Fuels (DOI: 10.1021/ef700395g).

32 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 15

Asphaltene Adsorption and Deposition Mechanisms Probed at the Local Scale Under Static and Dynamic Conditions: A New Opportunity of Neutron In-Situ Rheo-Reflectivity Measurements.

Yohann Corvis1, Nicolas Jouault1, 2, Fabrice Cousin2, Jacques Jestin2, Jérémie Gummel 1,2, Loïc Barré1.

1 Institut Français du Pétrole, 1-4 Av. de Bois Préau 92000 Rueil-Malmaison France. 2 Laboratoire Léon Brillouin, CEA/CNRS, CEA Saclay 91191 Gif/Yvette France.

Asphaltenes are the heaviest and most polar compounds of the crude oil in which they tend to aggregate to form nanometric fractal clusters [1]. Due to their surfactant properties, these aggregates can adsorb both at liquid-liquid interface [2] and solid-liquid interface [3]. From an industrial point of view, adsorption can have important effects such as wettability alteration in petroleum reservoirs. During oil production, the pressure decrease near the wellbore can also induce the flocculation of the asphaltene fractions resulting in reduction of the porous volume by pore blockage and/or multilayer formation. From a fundamental point of view, adsorption and deposition has been studied by global measurements such as surface excess [3] or core flood experiments [4], but less are the studies which have investigated the nanometer scale which is the characteristic size of the native asphaltene aggregates.

We present an original study of the asphaltene adsorption mechanisms on model solid surfaces using neutron reflectivity measurements on the time-of-flight EROS reflectometer at LLB. We have first investigated the adsorbed layer under static conditions at the liquid (toluene)-solid (silicon wafer) interface by studying the effects of the nature of the surface which can be hydrophilic or hydrophobic, and of the initial asphaltene aggregate sizes. The data can be fitted with a basic model: a single homogeneous adsorbed layer between two infinite media and a roughness parameter. The results show a direct correlation between the aggregate size in bulk and the resulting thickness of the adsorbed layer. Flocculation effects have been highlighted by addition of bad solvent (n-heptane) in the asphaltene solution: we measure in this case a direct increase of the asphaltene adsorbed layer.

The second part of the study concerns adsorption under dynamic conditions. A rheometer with a cone/plate geometry has been adapted on the EROS reflectometer and allowed us to perform new in-situ rheo-reflectivity measurements. Starting from the modelization computed under static conditions, we have studied, during bad solvent addition, the evolution of the asphaltene adsorption under controlled shear rates. In addition to the feasibility of a new kind of experiments, we demonstrate that the deposition rate is shear limited. This result is an important step forward on the comprehension of the mechanisms of plugging during production of unstable crude oils.

[1] L.Barré, S.Simon, T.Palermo, accepted to Langmuir (2007). [2] J. Jestin et al., Langmuir, 23 (21), 10471 -10478 (2007). [3] S. Acevedo et al. Colloids & Surfaces A , 166, 145-152 (2000). [4] L. Nabzar, M.E. Aguiléra, accepted in Oil & Gas Science and Technology – Rev. IFP (2007).

33 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 16

Two-Step Laser Desorption/Laser Ionization Mass Spectrometry of Asphaltenes

Andrew E. Pomerantz, Matthew R. Hammond, Amy L. Morrow, Oliver C. Mullins, and Richard N. Zare

Schlumberger

The chemistry of asphaltenes is a controlling factor in the phase behavior of crude oil and the production of heavy oil. However, the chemical complexity of asphaltenes makes them intractable for analysis by traditional laboratory methods. After decades of research employing a diverse set of techniques, even as fundamental a quantity as the asphaltene molecular weight distribution is still under dispute, with average measured molecular weights spanning orders of magnitude. Laser desorption ionization (LDI) experiments are particularly interesting in this regard, as different groups have measured asphaltene molecular weights differing by over 100-fold using similar LDI techniques on similar asphaltene samples. The ambiguity lies in the optimization of experimental parameters such as the sample concentration and laser power. Sufficient sample must be deposited to observe an experimental signal, and sufficient laser power must be applied to desorb the heaviest fraction of asphaltenes, or erroneously low masses will be recorded. However, some experimental evidence implies that excessive sample concentration and/or laser power can lead to aggregation in the plasma produced in LDI measurements, resulting in erroneously low measured masses. Proper interpretation of LDI measurements therefore requires an understanding of the influence of these different steps that are coupled in traditional LDI experiments.

In an attempt to clarify this controversy, we perform a two-step laser desorption/laser ionization mass spectrometry experiment (L2MS). In this technique, the desorption and ionization processes are separated in space and time. A layer of asphaltenes is deposited in a high vacuum chamber and is subsequently desorbed by an IR laser pulse (10 µm). Because the desorption photon energy is well below any asphaltene ionization potential, asphaltene molecules are desorbed without ionizing, and no plasma is produced. After a short delay, gaseous asphaltene molecules are ionized by 1+1 REMPI with a UV laser (266 nm), resulting in a low-density cloud of ions. The advantage of this two step measurement is that very high desorption power can be used, efficiently desorbing all fractions of asphaltenes; and that desorption occurs without producing a plasma, thereby avoiding potential aggregation. The performance of this technique is demonstrated by measuring the mass spectrum of both asphaltenes and model compounds over a range of both laser powers as well as the sample concentration. The two-step measurement therefore circumvents the problems that have complicated LDI measurements for decades, producing a reliable measurement of the asphaltene molecular weight distribution. We will present measured mass spectra of model compounds showing that L2MS efficiently desorbs a range of molecular weights without aggregation or fragmentation. Finally, we will present mass spectra of petroleum asphaltenes from several parts of the world; all petroleum asphaltenes examined are found to have most probable molecular weights of approximately 500-600 amu.

34 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 17

Fourier Transform Ion Cyclotron Resonance Mass Spectrometry: The Most Powerful Tool for Compositional Characterization of Petroleum and Its Relatives

Alan G. Marshall1,2,* Greg T. Blakney2, Brandie M. Ehrmann1, Christopher L. Hendrickson1,2, Priyanka Juyal2, Mmilili M. Mapolelo1, Amy McKenna1, Jeremiah M. Purcell2, Tanner M. Schaub2, and Ryan P. Rodgers1,2

1Department of Chemistry & Biochemistry, Florida State Univ., Tallahassee, FL 32306 2Ion Cyclotron Resonance Program, National High Magnetic Field Laboratory, Florida State University, 1800 East Paul Dirac Drive, Tallahassee FL, 32310-4005

It has been known for 50 years that sufficiently accurate (to ~0.001 Da up to ~600 Da) measurement of molecular mass can uniquely determine the molecule's elemental composition (CcHhNnOoSs…). During the past decade, it has become possible to realize that concept experimentally, based on ultrahigh-resolution Fourier transform ion cyclotron resonance mass spectrometry [1]. Various measures of FT-ICR MS performance improve linearly or quadratically with increasing magnetic field strength [2]. Thus, our 14.5 Tesla FT-ICR instrument provides optimal access to the rich information encoded in the masses of the molecules that comprise the chemically complex mixtures derived from petroleum: e.g., up to 50,000 resolved peak magnitudes exceeding 6s of baseline noise in a single FT-ICR mass spectrum. From the elemental compositions, species may be sorted by heteroatom class (numbers of N, O, and S atoms), double bond equivalents (DBE = rings plus double bonds to carbon), and carbon number. Moreover, the calculated DBE (integer vs. half-integer) of an ion can distinguish between odd-electron ions (e.g., M+•, as from five-membered pyrrolic rings) and even-electron ions (e.g., (M+H)+, as from six-membered pyridinic rings). MS/MS is beginning to identify functional groups. The introduction of internal standards is setting the stage for eventual quantitation of various compound classes. Applications include determination of molecular weight distribution, aromaticity, and alkylation for crude oil, distillates, bitumen, naphthenic acids, asphaltenes, deposits, and emulsions. Current FT-ICR MS benchmarks will be presented, along with ongoing and predicted future instrumental advances.

Work supported by NSF DMR-00-84173, Florida State University, and the National High Magnetic Field Laboratory in Tallahassee, FL.

1. Marshall, A. G.; Rodgers, R. P. "Petroleomics: The Next Grand Challenge for Chemical Analysis," Acc. Chem. Res. 2004, 37, 53-59. 2. Marshall, A. G.; Hendrickson, C. L.; Jackson, G. S. "Fourier Transform Ion Cyclotron Resonance Mass Spectrometry: A Primer," Mass Spectrom. Rev. 1998, 17, 1-35.

35 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 18

Could Naphthenic Acids be Responsible for Severe Emulsion Tightness for a Low TAN Value Oil?

Vincent Pauchard1*, Johan Sjoblom2, Sunil Kokal3, Patrick Bouriat4, Christophe Dicharry4, Hendrik Muller1, Adnan al-Hajji1, Ryan Rogers5

1 Research and Development Center, Saudi Aramco, Dhahran, Saudi Arabia 2 Ugelstad Laboratory, Norwegian University of Technology, Trondheim, Norway 3 EXPEC Advanced Research Center, Saudi Aramco, Dhahran, Saudi Arabia 4 Laboratoire des Fluides Complexes, UMR CNRS 5150, Université de Pau, BP 1155, 64013 Pau Cedex, France 5 Florida State University, USA * [email protected] The particular emulsion stabilizing properties of a low Total Acid Number (TAN) crude oil, first attributed to asphaltenes, were re-analyzed with respect to the role of naphthenic acids. Despite high asphaltene content and low organic acid content, this crude oil exhibits features classically observed with acidic crude oils, such as the dependency of emulsion stability on pressure/pH or the ineffectiveness of classical demulsifiers. This was confirmed by the high interfacial activity of indigenous acids as extracted from the crude oil by means of Ion Exchange Resins and by the high organic acid content in the interfacial material as extracted from a sludge emulsion. The physical origin of these phenomenological observations was probably identified using the Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR-MS) and pendant droplet experiments. The interfacial material was found to be composed of a mixture of asphaltenes and organic acids. These acids exhibit a wide range of structures (monoprotic, diprotic, fatty, naphthenic and perhaps aromatic) and molecular weights (from 200 to 700g/mol), contrary to the medium molecular weight fatty monoacids, generally believed to cause classical “soap emulsions.” The interfacial rheology was found to be the one of a 2D gel with an assumed glass transition temperature of approximately 40ºC. The conclusion of this study is that a synergistic effect of asphaltenes and organic acids promoted the build up of a very structured interface. This interface is more resistant to droplets coalescence than less structured interfaces. Therefore the disruption of the interfacial layer not only requires the drainage of individual molecules but also a collective yield of the gel.

36 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 19

Rupture of Interfacial Films at the Toluene-Water Interface

Sharath Mahavadi, Zhenghe Xu, Jacob Masliyah

Department of Chemical and Materials Engineering University of Alberta, Edmonton, Alberta, Canada

Water-in-oil emulsions formed during various stages of crude oil production pose a major challenge in the industry and demulsification of these emulsions is necessary for transportation and further processing in refineries. Chemical demulsification is one of the most convenient and economical methods for dehydrating water-in-oil emulsions.

The current study focuses on the rupture phenomenon of interfacial films in the demulsification process. Langmuir film studies with bitumen interfacial film with added demulsifier at a toluene-water interface suggest that a good demusifier can instantaneously alter the physicochemical properties of the interfacial films. Atomic force microscope and scanning electron microscope imaging of the Langmuir-Blodgett films show that the demulsifier at very low concentrations completely displaces the existing bitumen interfacial film. The UV-absorption spectroscopy, Auger electron spectroscopy and Auger elemental mapping have further revealed that the chemical nature of ruptured interface is similar to that of the demulsifier, thereby confirming the displacement of interfacial active material of bitumen by the demulsifier at the toluene-water interface.

37 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 20

The Formation of Rag Layers and the Role of Interfacial Partition of Naphthenates and Asphaltenes.

Kevin Moran1, Sumit Kiran2, Edgar J. Acosta2

1Syncrude Canada Ltd. 2University of Toronto, Department of Chemical Engineering and Applied Chemistry

The formation of rag layers – stable emulsions of oil and water – has been associated with the precipitation of asphalthenes and the formation of liquid crystal phases. In this work we present optical (transmission, cross-polarizer, and fluorescence) microscopy studies of rag layers produced under different conditions. These studies reveal that only under specific conditions (presence of un-dissociated naphthenic acids) liquid crystal formation is observed and correlated with the formation of rag layers. In the absence of naphthenic acids or in the presence of sodium naphthenates there no liquid crystal phases are observed, and the formation of rag layer is associated to the fraction of asphalthene “lost”. The word “lost” implies that the asphalthene fraction of the oil is reduced, however we do not suggest this means that all of this asphalthene has been precipitated. The optical micrographs reveal that the droplets of oil and/or water in the rag layer are not stabilized by the particles of asphalthene precipitated. These observations are explained using a hypothesis of asphalthene interfacial partition, whereby the asphalthene molecules tend to accumulate near the oil/water interface which form “skins” that prevent their coalescence and separation.

38 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 21

Effect of Film Area on Critical Electric Potential for O/W Emulsion Films Breakup

Farshid Mostowfi1*, Nikolay Panchev2, Jacob Masliyah3, Subir Bhattacharjee4,Jan Czarnecki3

1Schlumberger DBR Technology Center, 9450 17th Ave., Edmonton, Alberta, T6N 1M9, Canada 2Champion Technologies, Inc. Houston, Texas 77545, USA 3Department of Chemical and Materials Engineering, University of Alberta, Edmonton, T6G 2G6, Canada 4Department of Mechanical Engineering, University of Alberta, Edmonton, Alberta, T6G 2G8, Canada *[email protected]

Conventional thin liquid film breakup theories, such as long wave and pore nucleation theories, establish correlations between film area and probability of the film rupture; the larger the film area the less stable it is, and vice versa. To investigate the applicability of these theories to electric breakup of W/O emulsion films, critical potentials for breakup of lecithin films were measured at two different length scales using two different experimental setups. In both cases, an electric polarization was applied across an oil film formed between two separate water phases.

Conventional emulsion film experiments were performed using thin liquid film apparatus (Sheludko-Exerowa cell), in which the diameter of the films formed is of order of a few hundred microns which resembles films formed between millimeter sized droplets. A microfluidic device (Mostowfi et al., Applied Physics Letters, 90, 184102) was developed to form films between small micron sized droplets with a radius of curvature of 6.5mm. The device was comprised of glass micro-channels with embedded electrodes. The area of the films formed in the microfluidic device was about 150mm2 while those formed in the TLF apparatus were of the order of 200,000mm2 (500mm in film diameter). Despite the three orders of magnitude difference in film area, both techniques show critical potentials of the same order of magnitude. This raises the question as to whether conventional thin liquid film breakup theories are suitable for explaining electric breakup mechanism of W/O emulsion films.

Thin liquid films were formed in toluene using lecithin as surfactant. Lecithin molecules form bilayer films with a thickness of 4-6nm. Critical potential of breakup were measured over a wide range of lecithin concentrations from 0.05 up to 10 wt %. The value of critical potentials in both apparatus showed similar trends. At low surfactant concentrations, the critical potential for the film breakup was low due to less stable films at low surface coverage. At intermediate surfactant concentrations, the film stability as measured by critical voltage increases, which could be attributed to higher surface coverage with the surfactant. At high surfactant concentrations (>1 wt %), critical potential asymptotes to ~300mV. The saturation of critical potential could be explained by saturation of the interfaces with lecithin molecules.

39 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 22

Effect of Demulsifiers on Interfacial Films and Stability of Water-in-Oil Emulsions Stabilized by Asphaltenes

E.N. Baydak1, H.W. Yarranton1*, D. Ortiz1, K.Moran2

1Department of Chemical and Petroluem Engineering, University of Calgary, 2500 University Dr. NW, Calgary, Alberta, T2N 1N4 2Syncrude Research Centre, 9421-17 Ave., Edmonton, Alberta, T6N 1H4 *[email protected]

In previous work involving water-in-toluene/heptane emulsions stabilized by asphaltenes, a correlation was observed between emulsion stability and the compressibility of interfacial asphaltene films [1]. In this work, the effect of commercial demulsifiers on the film properties and emulsion stability is measured to determine if the correlation for emulsion stability is more generally applicable. To date, a naphthenic acid (NA) and a branched dodecylbenzene sulfonic acid (DDBS) have been examined.

Surface pressure isotherms were measured in a drop shape analyzer for droplets of asphaltenes, toluene, and heptane surrounded by a solution of water and surfactant. The experimental variables were: heptane content (0, 25, and 50 vol%), asphaltene concentration (0, 5, and 10 kg/m³), surfactant concentration (0, 0.1, and 0.5 wt% for NA; 0, 0.01, and 0.001 wt% for DDBS), and aging time (10 minutes to 4 hours). The compressibilities of the interfacial films were determined from the slope of the surface pressure isotherms. Water-in-oil emulsions were prepared from the same solutions. Emulsion stability was assessed in terms of the free water evolved after a treatment of centrifugation and heating.

Preliminary results indicate that, as expected, the demulsifiers increased the compressibility of the interfacial films. Contrary to expectation, in most cases, the addition of the demulsifier increased emulsion stability. The results appear to be independent of the timing of the addition of the demulsifier or the phase to which it is added. It is possible that the reduction in interfacial tension from the added surfactant inhibits coalescence more than the weakening of the interfacial film promotes coalescence.

[1] Yarranton, H.W., Urrutia, P., Sztukowski, D.M., J. Colloid Interface Sci, 310, 2007, 253-259

40 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 23

Dilational Rheology of Bitumen-Water Interfaces: Influence of Asphaltene Surfactants at Acidic and Neutral pHs

P. Chaverot1, Alain Cagna2, and Francis Rondelez

1Total S.A., CRES, BP 22, 69360 Solaize, France, 2IT Concept-Teclis, Parc de Chancolan, 69770 Longessaigne, France

Bitumen is a complex medium in which natural surface-active species are able to migrate towards the water-bitumen interface and lower the interfacial tension. This is of importance in the emulsification process since low interfacial tensions facilitate the formation of small bitumen droplets in water. In this paper we have investigated the interfacial properties of bitumen with high and low asphaltene contents, respectively. Their interfacial tension,?, and elastic modulus, E, have been measured by the hanging drop method at two different pHs. We observe that the ? values are systematically lower at pH 2 than at pH 7, and vice versa for the E values. We also observe a remarkable wrinkling of the interface when the droplet volume is mechanically reduced by suction, for one of the 2 bitumen investigated. Based on these results and additional controls, we conclude that asphaltenes contribute strongly to the interfacial behavior at acidic pH but are much less important at neutral pH. We also claim that different types of asphaltenes are probably at work depending on the particular bitumen, and that some of them are able to form two-dimensional networks acting as a non-elastic skin at the bitumen-water interface. We are presently trying to characterize the asphaltenes species involved by X- ray Photoelectron Spectroscopy.

41 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 24

On the Stabilization of Water in Crude Oil Emulsions

Jan Czarnecki

Dept. of Chemical and Materials Eng., University of Alberta, Edmonton

According to current, well established paradigm, asphaltenes and/or biwettable fine solids are solely responsible for water in crude oil emulsion stabilization. However, the material collected from W/O emulsion droplets (using Wu’s heavy water method) for a number of oil samples from various geographical locations (including Athabasca bitumen) and analyzed by Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR MS) was composed of similar low molecular weight (400 – 700 Da) molecules containing mostly carboxylic and thiophenic groups with double bound equivalents (DBE) of the most abundant species ranging from 2 to 8. Therefore, many of the species are not even aromatic, and most cannot be polyaromatic. As defined by the mass spectral results, the surface material does not fit a conventional description of asphaltenes, being heavy, polar, polyaromatic species. Microscope observations of emulsion and rag layer samples suggest presence of optically anisotropic species at the emulsified water droplet surfaces. Studies of phase equilibria in sodium naphthenate – toluene or heptane – water system indicate that naphthenate species are capable of forming organized phases, including liquid crystals. Although the nature of surface species and the exact mechanism of W/O emulsion stabilization are not yet understood in sufficient details, the current paradigm that asphaltenes and/or biwettable fine solids are responsible for water in crude oil emulsion stabilization is such a gross oversimplification that, in author’s opinion, it impedes further progress in the field.

42 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 25

Anticipating Flow Assurance Challenges Through Geochemistry

Matt Flannery

Fluid Evaluation and Sampling Technologies (FEAST) Team, Shell International Exploration and Production

Behaviour of reservoir fluids can present challenges at all stages of the petroleum value- chain, from reservoir to refinery. Sometimes such challenges are simply the result of sub-optimal operations or inappropriate system design, with assumptions of similar fluid properties across the field.

Hydrocarbon fluid phase behaviour is the product of local (reservoir and production) PVT conditions and the geochemical identity of the fluids. An appropriate development scenario, together with anticipation of production challenges, can benefit significantly from early integration of engineering and geochemical understanding of hydrocarbon fluids. This paper presents field examples of how the kerogen type and maturity, and later post-generation alteration processes (biodegradation, water washing, TSR) can influence likely flow assurance challenges in the production stream. It also illustrates the confounding issues of multiple charges and overlaying signatures.

43 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 26

A Quartz Crystal Microbalance Characterization of Metal-Oil Interfaces and Interactions with Wax Molecules

Kristofer Paso1,Thomas Kompalla1, Bjarne Braathen1, Narve Aske2, Hans Petter Rønningsen2, Tapani Viitala3, Johan Sjöblom1

1 Ugelstad Laboratory, Department of Chemical Engineering, Norwegian University of Science and Technology (NTNU), N-7491 Trondheim, Norway 2 StatoilHydro, N-4035 Stavanger, Norway 3KSV Instruments, FIN-00380 Helsinki, Finland

The solid-liquid interface between stainless steel and model petroleum fluids is investigated at isothermal conditions using a quartz crystal microbalance. AISI 316 (Fe/Cr18/Ni10/Mo3) stainless steel is chosen to represent the metal surface. Paraffin components dissolved in dodecane constitute the petroleum model fluid. Commercial macro-crystalline and micro-crystalline waxes provide primarily linear and branched paraffin components, respectively. Paraffin solubility conditions are established via a van’t Hoff relationship. Model fluids prepared with the single-component alkanes n-C36 or n-C30 paraffin provide well-defined solubility conditions. Monitored changes in resonance frequency and dissipation factor of the quartz crystal resonator immersed in the model fluids confirm that no continual deposition of paraffin components occurs at isothermal conditions. In addition, solid paraffin crystals dispersed in solution show no adherence to the stainless steel surface. The absence of attractive interactions between the stainless steel surface and dispersed paraffin crystals lends credence to a proposed axial transport mechanism for incipient wax deposit formation, where gelation kinetics play a primary role. QCM measurements performed under a thermal gradient also support these conclusions.

44 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 27

Dynamic Paraffin Deposition Experiments for Oil-Water Dispersions Created With South Pelto Oil and Garden Banks Condensate

Antonio Bruno, Cem Sarica, Hong Chen, Michael Volk

The University of Tulsa

Previous paraffin deposition studies have mostly focused on single-phase oil flow. Nevertheless, the presence of water along with the oil is increasingly common in everyday operations. This study investigated paraffin deposition under two-phase oilwater flow conditions in order to determine the effect that water concentration has on the deposition process. The results of this study help improve our understanding of paraffin deposition for dispersed flows of oil and water. A modified model proposed in this study can better predict paraffin deposition when compared to currently available models as a flow assurance tool in the design and analysis of production systems.

Two different crude oils with significantly different physical properties, South Pelto Crude Oil and Garden Banks Condensate, were studied extensively in the small-scale flow loop of Tulsa University Paraffin Deposition Projects. A total of eight oil-water deposition tests, two single-phase deposition tests, and two inversion point tests were successfully conducted. Four different water cuts were selected for each fluid.

The deposit thickness showed a decreasing trend with increasing water cuts for both the South Pelto oil and Garden Banks condensate tests. In contrast to South Pelto’s water continuous results, which showed no deposit, a Garden Banks condensate test with 85% water cut did generate a very thin and hard deposit film. This result indicates that there has to be a different deposition mechanism than the ones based on conventional diffusion theory.

A reduction in Reynolds number caused by the increased apparent viscosity of the mixture also resulted in a lower paraffin content of the deposits. The volume fraction of water in the deposit is lower than the initial water cut of the mixture for both fluids. Garden Banks showed less water fraction in the deposit compared to South Pelto. Couto et al.1 preliminary oil-water paraffin deposition model was validated against experimental data. Several modifications are proposed to account for water concentration in the deposit and changes in the diffusion coefficient for water dominated flows. Model predictions agree fairly well with experimental data acquired in this and previous studies.

1) Couto, G. H., Chen, H., Dellecase, E., Sarica, C., and Volk, M.: “An Investigation of Two-phase Oil-water Paraffin Deposition,” SPE Production & Operations Journal, February 2008.

45 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 28

Deposition From Wax–Solvent Mixtures Under Turbulent Flow: Effects of Shear Rate and Time on Deposit Properties

Ravindra Tiwary and Anil K. Mehrotra

Department of Chemical and Petroleum Engineering, University of Calgary Calgary, Alberta, Canada T2N 1N4

A bench-scale flow-loop apparatus1, incorporating a co-current double-pipe heat exchanger, was used for investigating the effects of deposition time and shear rate on the deposition of solids, under turbulent flow, from solutions of a multi-component wax in a paraffinic solvent. The deposition experiments were performed with two mixture compositions (10 and 15 mass% wax) at Reynolds numbers between 9000 and 27000 over a range of deposition times from 30 min to 24 h. The deposit mass was found to decrease with an increase in the Reynolds number, while it increased asymptotically with the deposition time. The deposit mass and density data were analyzed with a pseudo-steady-state heat transfer model1,2, 3 to study the variation in the deposit-layer thickness and thermal conductivity with shear rate and deposition time. The GC analysis of deposit samples showed noticeable changes in the carbon-number-distribution with shear rate and time, which supported the observed variations in deposit properties. The variations in deposit properties were also evaluated by using a recently proposed model, involving one-dimensional cubical-cage deformation4, which suggested the deposit-layer to undergo time-dependent plastic deformation due to the shear stress caused by the flowing liquid. The results of this study provide further evidence that the deposition from "waxy" crude oils is primarily a thermally-driven process, in which the shear stress and the deposition time play important roles by influencing the deposit properties.

1Fong, N.; Mehrotra, A. K. Energy & Fuels 2007, 21, 1263. 2Bidmus, H. O.; Mehrotra, A. K. Ind. Eng. Chem. Res. 2004, 43, 791. 3Parthasarathi, P.; Mehrotra, A. K. Energy & Fuels 2005, 19, 1387. 4Mehrotra, A. K.; Bhat, N. V. Energy & Fuels 2007, 21, 1277.

46 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 29

Rheology and FTIR Studies of Model Waxy Crude Oils with Relevance to Gelled Pipeline Restart

Jules J. Magda1, Kesia Guimeraes1, Milind D. Deo1, Rama Venkatesan2, Alberto Montesi2

1University of Utah, Chemical Engineering Department, Salt Lake City, Utah 2Chevron Energy Technology Company, Houston, Texas,

When ambient temperatures are low, crude oils being transported in pipelines sometimes form gels composed of wax crystals. These gels may stop the pipe flow, and make it difficult or even impossible to restart the flow without breaking the pipe. In order to investigate this problem, we are using rheology and FTIR techniques to characterize transparent model waxy crude oils that are also being studied in model pipeline flow experiments. Furthermore, these model oils were formulated without any highly volatile components, which we find greatly enhances the reproducibility of the rheology tests. Results will be presented for the time- and temperature-dependent rheology of the model waxy crude oils as obtained in linear oscillatory shear and in creep-recovery experiments. These results show that the model oils exibit many of the rheological features reported for real crude oils, such as three distinct apparent yield stresses : static yield stress, dynamic yield stress, and elastic-limit yield stress. Of the three, the static yield stress value and in particular its time dependence can best be used to predict the restart behavior observed for the same gel in model pipelines.

[email protected] [email protected] [email protected] [email protected]

47 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 30

Naphthenic Acid Extraction and Characterization From Crude Oils and Naphthenate Field Deposits Revisited.

Mohammed Murtala Ahmed and K. S. Sorbie

Institute of Petroleum Engineering, Heriot-Watt University, Riccarton, Edinburgh, EH14 4AS, Scotland, UK

Production of crude oil with high total acid number (TAN) poses a serious problem in the oil industry which often leads to the formation of either sodium emulsion or calcium naphthenate deposits. Calcium naphthenate formation during the production operations is increasing flow assurance problem for the oil industry, hence extraction and characterization of the different types of acids from the crude oils and the naphthenate field deposits is very important. There has been much discussion in the literature about the discovery and quantification of higher molecular weight acids in naphthenate field deposits, referred to as “ARN” acids. In this work, field naphthenate deposits from two different Norwegian fields (X and HD) were used for the naphthenic acid extraction using 3 different methods (which will be described). Characterization of the extracted naphthenic acids was carried out using electrospray mass spectrometry (ESMS) and atmospheric pressure chemical ionisation mass spectrometry (APCI-MS).

Our results show that ESMS spectra obtained from field X extract revealed the presence of lower molecular weight acids species only with no presence of ARN acids, whilst extract from field HD indicated broad range of lower molecular weight acids at around (m/z 200 to m/z 750) and ARN acid specie at around (m/z 1230 to 1240) . APCI-MS technique on the extracts revealed an enhanced ARN acids species from all the spectra with some of indication of multimers. Acid-IER extraction technique on the crude oils from these fields will also be discussed.

48 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 31

The Importance of Asphaltene Origin on its Behaviour in Production Systems

Mark Grutters, Artur Stankiewicz, Peter Cornelisse, Nancy Utech

Shell Global Solutions

For years, a heavy debate is taking place about the size and shape of asphaltene molecules. Evidence has been given for Archipellago-like structures, whereas others claim that the Island structure is more applicable. In addition, there is still no consensus on what the molecular weight of the asphaltenes is, as low as 300 g/mole or as high as 5000 g/mole or more. Although great progress has been made to characterize asphaltenes and although it is widely belived that smaller, more polar as well as more condensed asphaltenes are most problematic, to date there is little known about the relation between the size and shape of asphaltenes and their impact on flow assurance.

This lack of understanding is mainly related to the fact that the asphaltenes structure that we find in crudes depends on many geochemical processes that are usually not included as input for flow assurance studies. The geochemical processes that are important to asphaltenes are type of source rock and deposited organic matter, maturity, migration hiostory, and processes in the resevoir as hybridization and biodegradation. By carefully examining the geochemical processes relations can be found between asphaltene behavior in fields that are seemingly very different or distant. In our presentation, we will give some examples of these relationships. Understanding of asphaltenes structures is critical and warrants further development of methods for more accurate characterization. However, just the understanding of the fact that the universal aspahleten mocelule does not exist will help us in solving some production challenges related to this heavy fraction of crude oil.

49 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 32

Flow Assurance: Complex Phase Behavior and Complex Work Requires Confidence and Vigilance

Lloyd D. Brown

ConocoPhillips, Major Projects, Advanced Integrated Simulation

Real petroleum fluids and reservoirs are complex. Engineering definition is a key component of the foundation for managing project development concepts, cost, schedule, and execution structure. Reservoir fluid and its’ complexities at production conditions are the core of the engineering definition required to get the fluid from the reservoir to the market. As the price of oil and gas reach historic highs, more challenging reservoirs and fluids appear in the corporate search for reserves and production. Exploration and appraisal wells are each $50mm+. There are very few projects less than $0.5B and most greater than $10B+. Joint ventures are the rule rather than the exception. Real time research, change orders during project execution, and retrofits/problems during 10,000+ bopd production are expensive (and stressful). Safety and the environment are at the forefront of our design and change management. Predictability, Project Excellence, and Operations Excellence have become our mantras. Development decisions will be made that effect production of 100 mm+ barrels and 1B+ mmscf on typically much less than one barrel of fluid, a few cubic feet a gas, and a few appraisal wells. How much it cost is less heard than how quickly the answer can be delivered. Exploration, development, projects, and operations rely on flow assurance definition more now than ever. Your ownership of the answer is a given.

Flow assurance is an integrating discipline as it follows the fluid from the reservoir to the market. Flow assurance works across complex technical and non-technical interfaces, e.g. reservoir, completions, process, commercial, project management, physical/organic chemistry, fluid mechanics, chemical engineering, mechanical engineering, corrosion, etc.. Likewise, phase behavior in real fluids has complex interfaces. Flow assurance understanding, management, and communication of complex phase behavior must span ‘ivory tower’ academics to the ‘normal’ person in the field to enable proper selection, execution, and operation of development concepts designed to manage successful production within the fluid’s phase behavior. Simulation (correlation) tools allow us to translate science into engineering. Academic, industrial, and ‘field’ research is the core of these tools. Knowledgeable understanding of the fundamentals, the strengths, and the weaknesses is a discipline requiring more practice. We manage these complexities by innovation at utilizing the richness in the ‘signal’. However, we must always be wary of ‘group think’, complacency, and over confidence. Vigilance is required to assist and identify the right time to move innovation into the core tools. The flow assurance discipline must be vigilant on the periphery and confident in the core.

50 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 33

Reactivity Modeling of the Visbreaking of Athabasca Bitumen Using Molecular Representations

William C. McCaffrey1, Murray R. Gray1, Heather D. Dettman2

1Chemical and Materials Engineering, University of Alberta 2CANMET Energy Technology Centre - Devon, AB

A Monte Carlo approach was used to model the visbreaking of an Athabasca bitumen feedstock. A molecular representation was created for the Athabasca bitumen feed using a rule based construction algorithm. The molecular representation was consistent with many types of data: 13C-NMR spectroscopy, 1H-NMR spectroscopy, elemental analysis, vapor pressure osmometry, and simulated distillation. Sequential optimization was used to produce molecular representations that contained a minimum number of molecules (17 molecules for the entire feed). Each feed molecule was represented using connection and structural matrices. Model compound reactivity studies published in the literature were used to determine the probability of cracking of various C-C and C- S bonds. These probabilities were used in a continuous reaction algorithm that used matrix transformations to react feed molecules into product molecules. The reaction simulations were broken down into reaction steps. At each reaction step, molecules were first stochastically chosen to react, and then specific bonds were stochastically chosen to crack. Group contribution theory was used to calculate the boiling point of each molecule in the feed and product fractions. The Athabasca bitumen molecular representation was reacted until the degree of conversion of >500?C material was consistent with the experimental data. At this point, most feed molecules had multiple bonds cracked. The amount of <250?C liquid product produced was also consistent with the experimental data. The aromaticity, molecular weight, and sulfur content of the cracked liquid product were all consistent with the experimental properties.

51 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 34

Measurement of Hydrogen Bonding Capacity of Heavy Oil and Residues

Simon Ivar Andersen*, Runi Olsen, Türkan Inekci

Haldor Topsøe A/S R&D Refinery Processes/Emerging Technology Nymøllevej 55, DK-2800 Kgs. Lyngby, Denmark *[email protected]

Recently there has been an increasing interest in understanding the effects and fate of inherent hydrogen donor sites on the conversion of resid and heavy oil. The presence of quite large amounts of donor hydrogen in the residue indicates that this may be available for hydrogenation during conversion. Hence one may use this to explain some of the variations observed in apparently similar heavy feedstock in terms of reactivity during i.e. hydrodesulfurization and visbreaking. In a thermal process the donor H may suppress condensation reactions to coke, in agreement with the benefit of using hydrovisbreaking processes.

The dehydrogenation reaction using 2,3 dichloro-5,6-dicyano-p-benzoquinone (DDQ) reported first by Gould and Wiehe was investigated in terms of reaction conditions and parameters such as mixing and time of reaction. This confirms that the heavy fractions such as asphaltenes indeed poses substantial H-donors – and hence have a self-healing effect. This was also found for a series of hydrotreated products in which one can observe that the H-donor content is increased in the residue by stripping of lighter components.

From an analysis point of view we report the importance of anhydrous conditions and the reaction time. The use of different detection systems in GC-systems was also investigated for the final determination of the reaction products. In conclusion we have found that the when the H-donor reaction analysis is performed in a thorough manner, it can give insight into part of heavy petroleum fraction chemistry that has attracted little attention, although it is of obvious importance in both heavy oil upgrading and resid processing.

52 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 35

A Platform for Techno-Economic Analysis of Fouling Mitigation Options in Refinery Preheat Trains.

E.M. Ishiyama, W.R. Paterson and D.I. Wilson

Department of Chemical Engineering, University of Cambridge, New Museums Site, Pembroke Street, Cambridge, CB2 3RA, UK

The rise in crude oil prices has increased interest in improving the efficiency of heat transfer systems, particularly for the heat exchangers of crude oil preheat trains. Fouling in these units can result in reduced throughput, extra fuel consumption, or limits on distillation column operation. There are several mitigation options available, ranging from chemical (e.g. use of antifouling chemicals) to capital (new units, inserts or configurations). Selecting the best option requires a techno-economic analysis of the performance of the preheat train before and after modification. This requires simulation, to quantify the impact of molecular processes on unit performance and plant economics.

We shall present examples of the use of a new simulation tool that we have developed, incorporating the impact of fouling on the heat transfer and throughput of preheat trains. We examine dynamic phenomena, such as fouling rates dependent on temperature and flow, pump performance and flow splits across parallel sets of exchangers. The versatility of the tool is demonstrated by calculating optimal cleaning operations for a representative preheat train subject to fouling under (a) different energy and crude costs, and (b) impact of different fouling rates (e.g. simulating the use of chemical mitigation). We shall also demonstrate applications of the package to the consequences of column revamps.

53 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 36

Characteristics of Heavy Vacuum Gas Oil Fouling in the Presence of Dissolved Oxygen

Yonghua Li, Paul Watkinson

Department of Chemical and Biological Engineering The University of British Columbia Vancouver, BC, Canada V6T1Z3

Dissolved oxygen can lead to gum and deposit formation in hydrocarbon systems. A heavy vacuum gas oil (HVGO) was re-circulated through an annular heat transfer probe and the decline in heat transfer coefficient measured over periods of up to 200 hours, at bulk temperatures of about 85ºC, and initial surface temperatures in the range 260- 320ºC. The feed tank was saturated with nitrogen-air mixtures to yield oxygen pressures up to 100 kPa. Dissolved gum was determined by precipitation in n-heptane at 0ºC. Velocity was varied in the range 0.6 to 1.3 m/s.

Gum formation in the re-circulating system increased by roughly 1mg/L-h, giving dissolved gum concentrations of about 100 mg/L after 100-hours operation. Insoluble solids were of the order of 10 mg/L in the HVGO, which was pre-filtered before using in most fouling experiments. Initial experiments with unfiltered HVGO gave an order of magnitude higher fouling rates than subsequent experiments using HVGO that had passed through a 3-micron pore size filter. With filtered feed, induction periods before fouling took place were scattered. Examination of the heated surface showed that during the initial stages of fouling, gums formed in localized spots rather than as a smooth film. As fouling proceeded, the spots grew into patches which eventually covered the heated section of the probe. No deposition was found on the unheated section of the probe. At a surface temperature of 265 ±5ºC, in the absence of oxygen, fouling was below accurate detection limits. The rate of fouling increased strongly with oxygen pressures from 20 to 100 kPa. Velocity increases above 0.75 m/s resulted in decreases in fouling. Surface temperature effects were unusual, with rates appearing to increase only above about 290ºC.

Dissolved gum and deposit compositions were compared. Both gums and deposits contained about 6 % ash, 2 % sulphur, 3-5 % nitrogen and 20 % oxygen. Whereas gums had a H/C atomic ratio of about 1.2, in the deposits H/C was much lower at 0.5. The implications of the composition of the gums and deposits, and the mechanism of fouling are discussed.

54 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 37

Formation of Asphaltene Deposits from Crude Oil Destabilized by Addition of Propane

Jianxin Wang1, Jeff Creek1, Tianguang Fan2, and Jill Buckley2

1Chevron Energy Technology Company, TX, USA 2New Mexico Institute of Mining & Technology, NM, USA

Prediction of asphaltene deposit formation is increasingly of economic importance as oil developments move to deeper water and deeper wells. Building in the capability for asphaltene treatment in offshore deepwater developments is expensive, but failure to anticipate the need for such capacity would potentially be even more expensive. There is no deposition without precipitation of asphaltenes. Hence knowing the asphaltene stability as a function of temperature, pressure, and composition is the first step toward predicting deposition. Flocculated asphaltenes can segregate under the influence of gravity in low energy environments. The remaining problem is to understand the deposits that form on pipe walls in producing wells.

We report our continuing studies of arterial deposition from destabilized crude oils in stainless steel capillary tubing as a function of several variables, the most important of which is the molecular size of the paraffinic precipitating agent. Contrary to expectation, our previous work has shown that destabilization of asphaltenes from a given crude oil with higher molecular weight precipitants produces a larger volume of asphaltene- enriched deposit than does the use of a lower molecular weight precipitant with the same crude oil. Our previous studies focused on the liquid n-paraffins precipitants from n-pentane to n-pentadecane and the use of this data to forecast precipitation with solution gas at different pressures and temperatures. In this work, the range of paraffinic precipitants is extended to include propane. The deposition test results with propane will be compared to previous observations from tests with liquid n-alkanes driving the asphaltene precipitation. Results of this test are discussed as they apply to the case of reservoir fluids.

55 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 38

Recovery of Lighter Fuels by Cracking Heavy Oil with Zirconia-Supporting Iron Oxide Catalyst in a Steam Atmosphere

Eri Fumoto*, Akimitsu Matsumura, Shinya Sato, and Toshimasa Takanohashi.

Energy Technology Research Institute National Institute of Advanced Industrial Science and Technology, 16-1 Onogawa, Tsukuba 305-8569, JAPAN. * [email protected]

Catalytic cracking process of heavy oil, such as petroleum residual oil, with zirconia- supporting iron oxide catalyst in a steam atmosphere was investigated to recover lighter fuels as much as possible. In this process, steam was decomposed on the catalyst, yielding active oxygen and hydrogen species. Heavy oil was oxidatively cracked with the oxygen species, and lighter fractions and carbon dioxide were generated with almost no coke. While, the active hydrogen species were added to the heavy and middle fractions, producing gasoline, kerosene and gas oil. Large amounts of these lighter fuels were produced by the catalytic cracking of heavy oil with zirconia-supporting iron oxide catalyst at 773 K, while the amount was a little at 723 K. To promote cracking of heavy oil at lower temperature, alumina was mixed to the catalyst. As a result, this catalyst was found to be so active to cracking heavy oil even at 723 K, and the total amount of lighter fuels was as large as that at 773 K.

56 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 39

Complex Phase Behaviour in Bitumen Upgrading

J. M. Shaw

Department of Chemical and Materials Engineering University of Alberta

Phase behaviour measurement and prediction related to Athabasca bitumen or bitumen vacuum residue + other hydrocarbon + gas mixtures are addressed. From a theoretical perspective these mixtures are classified as asymmetric. Key aspects of their phase behaviour are anticipated from theory. For example, these mixtures exhibit mutiphase fluid and solid behaviours and critical phenomena which can enhance or inhibit desirable separation and reaction outcomes for a spectrum of refining processes. The phase behaviour of asymmetric mixtures is reviewed. Phase diagrams and practical examples drawn from our experiences with deasphalting and hydrogenation process applications are highlighted. Some observed effects appear at first blush to be counter intuitive. Ongoing efforts targeted at the development of reliable molecule-based energy and equation-of-state models for the prediction of the phase behaviour for such mixtures are discussed.

Selected Bibliography:

Lastovka, V., Sallamie, N., and Shaw, J.M., A similarity variable for estimating the heat capacity of solid organic compounds Part I. Fundamentals, Fluid Phase Equilib. (2008), in press. Zhao, B., Zhang, Xiaihui and Shaw, John M., The Interplay between the Physical Properties of Athabasca Bitumen + Diluent Mixtures and Coke Deposition on a Commercial Hydroprocessing, Energy & Fuels 2008, in press. Saber, N. and Shaw, J.M., Rapid and robust phase behaviour stability analysis using global optimization, Fluid Phase Equilibria 264 (2008) pp. 137-146. Zou, Xiangyang, Zhang Xiaohui and Shaw, John M., The Phase behavior of Athabasca Vacuum Bottoms +n-Alkane Mixtures, SPE Production & Operations, Vol. 22, No. 2, pp. 265-272, May 2007. Zou, X.Y., Shaw, J.M., Phase Behavior of Heavy Oils. Asphaletenes, Heavy Oil & Petroleomics, Mullins ed., 19, 485-505, 2006. Zou, X.Y., Shaw, J.M., Phase Behavior of Hydrocarbon Mixtures. Encyclopedia of Chemical Processing, pp. 2067-2076, 2006. Zou, X.-Y. Dukhedin-Lalla, L., Zhang, X., Shaw, J.M., Selective Rejection of Inorganic Fine Solids, Heavy Metals, and Sulfur From Heavy Oils/Bitumen Using Alkane Solvents, Industrial Eng. & Chem. Research. Volume 43, Issue 22, pp. 7103-7112, Oct. 2004. Shaw, J.M.,Toward Common Generalized Phase Diagrams for Asphaltenes Containing Hydrocarbon Fluids, ACS Petroleum Chemistry Div. Preprints, 47 (4), 338-342 (2002). Abedi, S. J., Cai, H.-Y., Seyfaie, S. and Shaw, J. M., Simultaneous Phase Behavior, Elemental Composition and Density Measurement Using X-Ray Imaging, Fluid Phase Equilibria, 158-160, 775-781 (1999). Abedi, S.J., Seyfaie, S. and Shaw, J.M., Unusual Retrograde Condensation and Asphaltene Precipitation in a Model Heavy Oil Systems, Pet. Sci. & Tech., 16 (3&4), 209-226, 1998).

57 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 40

Study of the Gelation Behaviour of Brazilian Waxy Crude Oils

Cláudio M. Ziglio, Daniele F. Sant’Ana

Petróleo Brasileiro S.A., PETROBRAS, Ilha do Fundão, Q.7, 21941-598, Rio de Janeiro, e-mail: [email protected]

The production and transportation of waxy oils is considered a major operating issue for the petroleum industry. The wax precipitation, caused by the oil temperature reduction during the production, leads to the formation of a paraffin network which evolves into a gel structure. A gelled oil in a pipeline can require a very high re-start pressure, which sometimes is beyond the available pump capacity. The gelation of the oil can also develop into a wax deposit on the pipeline walls, which restricts the crude oil flow. Hence, a thorough understanding of the wax gel properties is essential to predict and avoid problems during waxy oil transportation.

We have applied rheometry tests to study the yielding process of wax gels formed by the cooling of Brazilian crude oils. The effect of selected chemical additives on the gel strength was also investigated.

Considering a rheological approach, the oil-gel transition occurs when the solidlike behavior of the fluid becomes predominant over its liquid-like behavior. Hence, dynamic rheology has been employed to study the oil-gel transition under quiescent conditions. The temperature at which the crude oil gels was determined through the relation between the loss modulus (G’) and storage modulus (G”).

To study the gel yield stress, which is related to the gel strength, we applied two rheological methods. In the Creep and Recovery method a stress is applied to the sample for a short period while the resulting deformation is measured. Then the stress is removed to allow the sample to recovery the gel structure. The steps of creep and recovery are repeated with an increasing stress value. The yield stress was identified as the minimum stress to cause an irreversible deformation in the sample.

Dynamic measurements were also performed as a method to estimate the yield stress of the gelled oil. The yielding process was induced by an increasing oscillatory strain with a low frequency (0.5 Hz). The gel breakdown occurs when the sample is submitted to a critical strain, which is related to the yield stress value.

The effect of 4 commercial chemical additives was investigated using the rheological experiments in the dynamic and steady-state (creep and recovery) modes. The results indicate that the gelation temperature can be significantly reduced by the addition of small amounts of readily available additives. It was also found that theses additives impact on the yield stress values, thereby reducing pump pressure in a cold re-start situation.

58 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 41

‘Cold Flow’ Deposition Experiments with Wax–Solvent Mixtures under Laminar Flow in a Flow-Loop with Heat Transfer

Hamid O. Bidmus, Anil K. Mehrotra

Department of Chemical and Petroleum Engineering, University of Calgary Calgary, Alberta, Canada T2N 1N4

'Cold Flow' of "waxy" crude oils in pipelines occurs at temperatures between the wax appearance temperature (WAT) and the pour point temperature (PPT). It has been suggested as an alternative technique for decreasing the extent of solids deposition. In 'cold flow', the formed wax crystals remain suspended in the flowing crude oil. An experimental investigation was undertaken to study solids deposition under 'cold flow' in a novel flow-loop apparatus, incorporating a small double-pipe heat exchanger. The experiments were performed with 2 and 6 mass% mixtures of a petroleum wax dissolved in Norpar13 (a paraffinic solvent comprising C9–C16) at different wax–solvent mixture temperatures (Th) over a deposition time of 1 h. Two sets of deposition experiments were performed with (WAT > Th > PPT) and (Th > WAT). Following each experiment, the deposit-layer was recovered and analyzed for mass, density, and composition. Both sets of results were analyzed with a pseudo-steady-state heat transfer model, 1 and the relative magnitudes of all thermal resistances were compared. It was noted that, with (Th > WAT), the deposit mass increased with a lowering of Th, which is in agreement with 1,2,3 the results reported previously. However, under cold flow, with (WAT > Th > PPT), the deposit mass actually decreased with a lowering of Th. This was attributed to a lowering of the wax concentration of the liquid phase, due to the precipitation of heavier alkanes as wax crystals (in suspension), which resulted in a lowering of its WAT. The results of this study indicate that a smaller deposit-layer thickness can be achieved during cold flow of "waxy" crude oils.

1Bidmus, H. O.; Mehrotra, A. K. Ind. Eng. Chem. Res. 2004, 43, 791. 2Parthasarathi, P.; Mehrotra, A. K. Energy & Fuels 2005, 19, 1387. 3Fong, N.; Mehrotra, A. K. Energy & Fuels 2007, 21, 1263.

59 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 42

Comparison and Structural Elucidation of Naphthenic Acids Found in Sodium and Calcium Naphthenate Deposits by Electrospray Ionization Fourier Transform Ion Cyclotron Resonance Mass Spectrometry

Andrew Yen1, Sam Asomaning1, Mmilili M. Mapolelo2,3, Ryan P. Rodgers2,3 and Alan G. Marshall2,3

1Baker Petrolite, 12645 W. Airport Blvd, Sugar Land, Texas 77478 2Department of Chemistry & Biochemistry, Florida State Univ., Tallahassee, FL 32306 3Ion Cyclotron Resonance Program, National High Magnetic Field Laboratory, Florida State University, 1800 East Paul Dirac Drive, Tallahassee FL, 32310-4005

Calcium and sodium naphthenates are respectively solid deposits and emulsions formed by the interaction of naphthenic acids with divalent (Ca2+, Fe3+, Mg2+) or monovalent (Na+, K+) ions in produced water. Calcium naphthenate formation, an interfacial phenomenon, is thought to depend largely on tetraprotic naphthenic acids known as "ARN" acids in the crude, whereas the formation of sodium naphthenate originates from less substituted lower molecular weight naphthenic acids. These generalities, though, are based on different purification methods, some of which may result in the exclusion or possible revelation of important components.

We present class comparison variation in different naphthenate deposits by FT-ICR MS. The high resolution and mass accuracy of FT-ICR MS provides detailed acidic speciation (composition) for the deposits. The class composition of the calcium naphthenate deposits differs significantly when different preparatory steps are applied. O8 class (tetra-acid) was detected in all calcium naphthenate deposits, but not in all of the sodium naphthenate samples. O5 class species were identified in calcium naphthenate deposits washed with methylene chloride. Other classes such as O6, O9 and O10 found in other deposits were also identified. We further discuss the structural elucidation of the naphthenic acids (classes) found in the deposits through MSn techniques such as Collision Activated Dissociation (CAD) and InfraRed MultiPhoton Dissociation (IRMPD). Class analysis in the naphthenate deposits revealed significant dissimilarities that likely account for the diverse morphological and physical properties of the two deposits.

Work supported in part by NSF (DMR-00-84173), Florida State University, and the National High Magnetic Field Laboratory in Tallahassee, FL.

60 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 43

Comparison of Crude Oil Interfacial Behavior

Jan H. Beetge and Nikki Panchev

Champion Technologies, Inc., 3130 FM RD. 521, Fresno, Texas 77545, USA. [email protected]

Traditional characterization of crude oil, such as SARA analysis, is focused on the bulk properties of crude oil. The information from such characterization is used to understand or predict behavior that will be relevant in the treatment, transport and processing of crude oil. Surface active components such as asphaltenes are often extracted to study or explain critical interfacial behavior of crude oil. However, there seem to be little attention given to the characterization of the surface active component of crude oil in its natural composition.

This study is a pragmatic attempt to explore the differences and similarities in the interfacial behavior of the collective surface active component in various crude oils from different sources. A Teclis drop shape tensiometer was used to compare the properties of interfaces between crude oil and water. In these experiments, a portion of a crude oil sample is diluted in toluene and contacted with water in a rising drop configuration. Dynamic surface tension and interfacial rheology is studied as a function of time from the early stages of interface formation. Sinusoidal oscillation of the drop volume allows the evaluation of visco-elastic behavior of the crude oil/water interface as it develops with time. The Gibbs elastic modulus, as well as its elastic and viscose components are calculated from the drop shape. The observed interfacial behavior is expressed in terms of concentration, oscillation frequency and interface age.

Since the interfacial behavior of a crude oil can be expected to play a significant role in crude oil production and processing, it is possible that knowledge of crude oil interfacial character could be of value in the treatment, transport and processing of crude oils.

61 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 44

Physical and Chemical Properties of Deasphalted Oil and Asphaltenes from Laboratory Deasphalting Experiments on Alberta Bitumen

David W. Jennings1 and Irv Wiehe2

1 Baker Petrolite, 12645 W. Airport Blvd., Sugar Land, TX 77478, [email protected] 2 Soluble Solutions, 3 Louise Lane, Gladstone, NJ 07934, [email protected]

This presentation will cover results from an extensive series of laboratory deasphalting experiments on Cold Lake and Athabasca Bitumen performed with various solvents and solvent combinations (ranging from aliphatic to aliphatic/polar to polar solvents) at different temperatures and solvent/bitumen ratios. The purpose of the work was to study the physical and chemical properties of deasphalted oil and asphaltenes resulting from different deasphalting conditions.

By altering the deasphalting conditions, the deasphalting procedure provided a simple separation method for obtaining different fractions of asphaltenes; ranging from approximately 6 to 21 wt. % of the total bitumen samples. Within the range of conditions studied, the primary influence on the properties of the deasphalted oil and asphaltenes was found to be related to the amount of deasphalting occurring. For equivalent amounts of asphaltenes removed, no significant differences were observed in experiments with differences in solvent type, temperature, or solvent/bitumen ratio.

The deasphalted oil properties evaluated included metals content, microcarbon residue content, C,H,N, & S content, and viscosity. The asphaltene properties evaluated included metals content, microcarbon residue content, C,H,N, & S content, and molecular weight from VPO.

The deasphalted oil properties increasingly improved with increasing amounts of deasphalting with respect to reduction of metals content, microcarbon residue content, and viscosity. Also, elemental sulfur and nitrogen tended to decrease and H/C ratios tended to increase with increasing asphaltene removal. For the asphaltene properties, the first asphaltene fractions removed were found to contain higher metals content, microcarbon residue content, and molecular weight. Removal of these asphaltene fractions also gave greater viscosity reduction than subsequent removal of additional asphaltenes.

62 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 45

A Bulk Rheological Investigation of Crude Oils from Various Sources.

Geoff Robinson*1 , Jannie Beetge1

1Champion Technologies, 3130 FM 521, Fresno Texas, 77545 U.S.A.

*[email protected]

It is well known that a comparison of the rotational viscosity (?) of one crude oil with another can show orders of magnitude differences.

We have extended the usual viscosity characterization to include the bulk rheological properties such as the solid like modulus, the liquid like modulus and dynamic viscosity (G’, G’’ and ?*) over the temperature range 0-80 deg C.

Initially, two oils with similar SARA properties were chosen whose viscosities differed by three orders of magnitude at 25 deg C. Properties such as G’, G’’, ?* and ? were measured as a function of temperature. Essentially both oils showed liquid like characteristics (G’’ > G’) but G’ in both cases showed a series of structural build-ups and breakdowns, and in some cases showed very specific transitions at certain temperatures.

The behavior of ?* often followed the changes in G’ consistent with structural build up.

Normally we would expect ? to be less than ?* but this was not the case with the more viscous oil.

The maltene fraction of both oils were separated and studied in a similar manner. Significant differences were noted between the two maltene fractions, as well as between the neat crude oil and its corresponding maltene fraction.

The investigation was extended to other crude oils and correlations with SARA analysis are presented and discussed.

63 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 46

Phase Behavior and Physical Properties of Athabasca Bitumen, Propane and CO2

Yarranton, H.W., Badamchizadeh, A., Satyro, M.A., Maini, B.

Department of Chemical and Petroleum Engineering, University of Calgary

There is a growing interest in solvent based processes to recovery heavy oil because steam-based processes are energy intensive and are drawing on a limited water supply. The design and optimization of these processes is hampered by limited data and modeling capability for mixtures of heavy oils and solvents. In this work, mixtures of propane and CO2 with Athabasca bitumen were considered.

Saturation pressures were measured in a PVT cell and the density and viscosity of the saturated liquid phase were determined at temperatures between 0 and 50°C and pressures up to 5 MPa. Data are reported for CO2-bitumen, propane-bitumen and two propane-CO2-bitumen mixtures. Vapour-liquid and some liquid-liquid and vapour-liquid- liquid phase boundaries were determined. Regions where multiple liquid phase formation is likely were identified.

A simple analytical methodology for determining the vapour-liquid phase boundary for each mixture was developed. An equation of state was also tuned to fit these boundaries.

64 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 47

Liquid – Solid Phase Equilibrium of Tetradecane + Dodecyl-Cyclohexane System Under Pressure.

J.-L. Daridon1,*, M. Cassiède1 , M. Milhet1 , J.A.P. Coutinho2, and J. Pauly1

1 Laboratoire des Fluides Complexes – UMR 5150 – B.P. 1155 – 64013 Pau Cedex, France 2 CICECO – Universidade de Aveiro – 3810–193 Aveiro, Portugal * Corresponding author. Tel.: +33 5 59 40 76 89; fax: +33 5 59 40 76 95. E-mail address : [email protected]

Petroleum reservoir fluids, like heavy oils or gas condensates, contain high molecular weight hydrocarbons which may precipitate as a waxy solid phase when conditions of temperature and pressure change during production and transport. Wax deposition on the walls of the production equipment or along flow lines reduces the diameter of the tubing and may obstruct them completely if it is not prevented. This process is mainly due to a change of both pressure and temperature conditions as well as fluid composition during the production. In order to avoid this phenomenon it is essential to be able to predict, by the use of thermodynamical models, the wax appearance temperature (WAT) as well as the behavior of the solid waxy phase below the WAT. Most often, the waxy solid precipitating is assumed to be formed of linear alkanes and only these compounds are taken into account in usual models. However, the heavy fraction is composed of other components than normal paraffins. In particular, some high melting temperature iso-paraffins or naphthenes can be present in significant proportion and can thus participate or interact on the wax formation. Phase equilibria of heavy paraffins with other compounds have been little studied while extensive work has been performed on paraffin mixtures. It is therefore necessary to conduct studies of liquid-solid phase equilibrium on systems made up of normal paraffins + high molecular weight iso- paraffins or alicyclic hydrocarbons. With this aim in mind, we have studied in this work, the liquid-solid phase diagram of the {tetradecane + dodecyl-cyclohexane}binary mixture. Measurements were carried out up to 100 MPa using a cross polar microscope.

65 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 48

Further Adventures in Binding Resins: Investigations into Asphaltene - Binding Resin Interactions

Brendan. F. Graham1,*, Eric F. May1 and Robert. D. Trengove2

1School of Mechanical Engineering, University of Western Australia, Crawley, W.A., Australia 6009 2Separation Science Laboratory, Murdoch University, Murdoch, W.A. Australia 6150 *[email protected]

For the producers and processors of hydrocarbon fluids, emulsions of crude oil and formation water often cause serious problems that require expensive solutions. Such emulsions can often have a viscosity an order of magnitude larger than that of the free oil and therefore, avoiding them is a flow assurance challenge. Once at the processing site the emulsion must be broken to recover the oil for further processing. To overcome the problems associated with emulsions, various techniques have been developed such as the application of heat, and the injection of demulsification chemicals, for example, at the well head or the processing facility. Invariably these remedies are costly; however given the consequences of emulsion formation, they are often employed as a pre- emptive measure. This is despite the fact that it is extremely difficult to predict reliably whether an emulsion will actually form in a given production system.

In previous work we fractionated a series of West African and West Australian crude oils into the four standard solubility classes: saturates, aromatics, resins and asphaltenes (SARA). The asphaltene fraction was then separated further into classes we have called binding resins (BR) and residual asphaltenes (RA) using a solvent of near-boiling heptane. The ratio  º BR / RA correlates strongly with the tightness of water-in-oil emulsions that these oils formed either in the field or the laboratory with higher ratios correlating to weaker emulsions. Initial identification of the major components of the binding resins was conducted with multidimensional GC-MS

In this current work the interactions and structures of the asphaltenes and binding resins have been investigated by various techniques. Laboratory experiments have shown that binding resins once separated from their co-precipitated asphaltenes will, at least partially, recombine in solution. Calorific and gravimetric methods were used to investigate the binding kinetics as well as to determine the stoichiometry of the binding resin-asphaltene complex.

Matrix assisted laser desorption ionisation mass spectrometry was used to study the mass distribution of the binding resins and asphaltenes both before and after recombination to study the differences in stoichiometry and binding strength. High temperature GC analysis of the resin/asphaltene complex has shown the bonding to be thermally stable at temperatures in excess of 350 °C and this will be further investigated through the use of thermo-gravimetric analysis.

66 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 49

Asphaltene Equilibrium in Oil Columns with Varying GOR

Denise Freed, Kentaro Indo, John Ratulowski and Oliver Mullins

Schlumberger

Recently, it was shown that oil columns can have gradients in the amount of asphaltenes due to the buoyancy effect. Condensates can also have large gradients in the GOR, their equilibrium distribution will be affected not only by gravity, but also by the changing solubility of the maltene. In this poster, we will present a simple model to treat both the gravitational effects and the changing solubility of the oil. We will show how the equilibrium distribution of the asphaltene can be obtained as a function of the height and the composition of the maltene, and in particular, the solubility parameter of the maltene. We will compare the results of this model with centrifugation data on a model system containing methane, pentane, and 1-methyl naphthalene.

67 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 50

Interaction Between Asphaltenes and Minerals in Asphalt Mixtures

Roberto Carlos Ribeiro1,2, Julio Cesar G. Correia1 & Peter R. Seidl2

1Centro de Tecnologia Mineral – CETEM. Av. do Ipê, 900. Ilha da Cidade Universitária, Rio de Janeiro – RJ. Cep: 21941-590, [email protected]; [email protected] 2Universidade Federal do Rio de Janeiro, UFRJ, Escola de Química, Ilha da Cidade Universitária, Rio de Janeiro – RJ, [email protected]

The adsorption of five asphalts processed in Brazilian refineries and designated A, B, C, D and E, and their asphaltenes and maltenes constituents, from toluene solutions onto gneiss and their minerals, quartz and feldspar, and the relationship between this tendency and the mechanical properties of the asphalt pavement have been investigated. For all minerals the asphalts A and C were wore strongly absorbed the others. Their respective curves leveling off between 3.5 and 4.0 mg.g-1 for gnaiss and quartz, increasing to 5 and 6 mg.g-1 for feldspar. The contact angle of quartz was not modified by the adsorption of asphaltenes in contrast to that observed for feldspar, indicating that the sites responsible for the surface of the latter minerals were affected by the presence of the adsorved organic species, and that was not observed for the maltenes. Regarding tests of the mechanical resistance of asphalt mixtures, only asphalts A and C gaves that would be considered values acceptable by the Brazilian National Department of Terrestrial Infra-structure (DNIT). These results indicate that the chemical interaction among minerals and asphalt affects the mechanical resistance of the asphalt mixture. Besides, it is verified that the asphaltenes are the responsible for the best adsorption with the surface of the minerals, and that such a process is related with the resistance of asphalt pavement.

68 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

Abstract 51

Interfacial Tension Change Due to Asphaltene Flocculation in Recombined Oils

H. Carrier1, J. Pauly1, A. Mejia1,2, J. Castillo2 and JL Daridon*1

1Laboratoire des Fluides Complexes, Université de Pau 2Universidad Central de Venezuela, Facultad de Ciencias. * [email protected]

Reservoirs fluids can contain asphaltenes in various proportions. These complex high molecular components may be dissolved or present as colloidal aggregates in crude oils. However, due to changes in both temperature and pressure, those aggregates may be destabilized, leading to the flocculation of asphaltenes. Moreover, the variations in oil composition caused by liquid-vapour phase separation, gas injection or oil blending can also lead to asphaltene flocculation. The insolubility of asphaltenes is generally the cause of huge problems at different stages of the production. Asphaltene flocculation generally induces solid deposition and adherence on the walls of the equipments leading to a restriction of the flow and a diminution of the productivity. It can even plug the wellbore if the phenomenon is not treated and then stop the production. The prevention and the remediation of asphaltene deposition during exploitation, transportation and refining process still represent a major challenge for the Petroleum Industry. In order to evaluate the risk of asphaltene formation and to design techniques to prevent or to remove asphaltene deposits it is essential to be able to measure and predict the conditions of flocculation throughout the pressures encountered from reservoir to surface conditions.

So far, most of the asphaltene stability studies were undertaken at atmospheric pressure for dead oils by adding precipitating solvents. However the relationship of these stability tests with asphaltene flocculation due to the decompression of live oil in reservoir or production conditions is not yet really established. Accurate measurements on both atmospheric and field conditions are needed. With the aim of doing such measurements we have designed a high-pressure device using refractive index measurements and a filtration technique [P1, P2] to measure onset of asphaltene flocculation in live oils. In this work we have extended the capacity of the device to investigate the evolution of the interfacial tension between crude oil and gases or immiscible liquids like water at pressures up to 70 MPa. In this additional part interfacial tension measurements are performed by axisymmetric drop shape analysis of a pendant oil drop.

Measurements were conduced on recombined oils. The results established a relationship between the discontinuity in the trend of the superficial tension as a function of the pressure and the threshold of asphaltenes aggregation due to decompression. Evidence of the effect of asphaltenes flocculation on the IFT is demonstrated.

[P1] S. VERDIER, H. CARRIER, S. ANDERSEN, J-L DARIDON . A study of pressure and temperature effects on asphaltene stability in presence of CO2 Energy and Fuels, 20, (2006), 1584-1590 [P2] J. CASTILLO, S. ACEVEDO, C. CANELON, H. CARRIER, JL DARIDON Optical fiber extrinsic refractometer to measure refractive index at high pressure and high temperature: application to wax and asphaltenes precipitation measurements Fuel, 85, (2006), 2220-2228

69 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 52

Sedimentation of Asphaltenes Dissolved in Toluene Using Ultracentrifugation Technique

Richard McFarlane1, Philip Chong1, Farshid Mostowfi 2*, and Oliver Mullins3

1Alberta Research Council Inc., 250 Karl Clark Road, Edmonton, Alberta, T6N 1E4, Canada 2Schlumberger DBR Technology Center, 9450 17th Ave., Edmonton, Alberta, T6N 1M9, Canada 3Schlumberger Doll Research Center, 1 Hampshire St, Cambridge, MA 02139 USA * [email protected]

Recent work reported by Mullins and co-workers (Energy & Fuel, 2007, 21, 2785-2794) indicated that asphaltenes could sediment in an oil formation under normal gravity. The concentration gradient of asphaltenes in the reservoir was used to infer an average diameter of about 2 nm which is in the colloidal range. In this case, sedimentation would have occurred over geological time in this oil (Tahiti field, Gulf of Mexico). Sedimentation experiments are carried out on dilute solutions of asphaltenes in toluene using an ultracentrifuge. For this work, the concentration of asphaltenes in solution was kept low enough (250 mg/L) such that the size of asphaltene aggregates, which changes with concentration, remains relatively small. The concentration gradient of asphaltenes in the centrifuge tube is monitored using near infrared spectrometry technique at three different centrifugation periods (7, 17, and 30 days). The total liquid sample recovered in every case contained about 75% of the initially added asphaltenes. In other words, 25% of the dissolved (or dispersed) hydrocarbons settled to the bottom of the tube within seven days. This settled material was observed near the bottom of the tube as an ellipsoid of black sediment on the wall of the tube. Given the geometry of the system and an average field of 25,000 g’s, these results imply a minimum size of settled asphaltenes of 2.5 nm at Stokes settling velocity.

The observed settling behavior entails for asphaltenes in toluene at a concentration of 250 mg/L about 25% of the asphaltenes exist as aggregates which settle out within the first seven days at 25,000 g’s. The remaining asphaltenes may be molecularly dispersed and less than 1.2 nm in diameter so that there is no settling after even 30 days. The aggregate concentration measured in this work leads to a concentration of 190mg/L for CNAS (critical nano-aggregate concentration) which is in accord with the value of 200mg/L reported in literature using NMR measurements. The role of ultra-fine organic solids in sedimentation of the asphaltenes cannot be ignored since the asphaltenes used in these tests are estimated to contain up to 5.5 wt.% of inorganic solids. Asphaltenes are known to adsorb on minerals such as kaolinite. If nano-sized asphaltenes were to be associated with micron-sized inorganic solids (or organic) this could lead to rapid settling. One alternative explanation to the role fine solids in sedimentation is that of increasing aggregation and settling due to the concentration gradient created in the settling field. As settling proceeds, aggregates of certain size begin to settle and increase in concentration towards the bottom of the tube from low gravity field to high gravity field. At some concentration limit, these aggregates may grow into large aggregates and their settling rates increase.

70 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 53

Study of Asphaltenes Aggregation by Dynamic Light Scattering

Maria A. Ranaudo, Jimmy Castillo, Héctor Gutiérrez*

Universidad Central de Venezuela, Facultad de Ciencias, Escuela de Química P.O. box 40720, Caracas 1041A, Venezuela. * [email protected]

Asphaltene chemical composition and structure are topics of great interest and controversy, knowledge of these characteristics helps to improve the aggregation models and to better understand all the physical-chemical properties associated with asphaltenes. Different techniques have been employed to estimate the molecular weight and size of asphaltene and their aggregates.

Dynamic light scattering (DLS) it’s a well know technique to measuring the mean particle size in nanometer scale. In this technique, the time-dependent autocorrelation function G(t) of scattered light from a dispersion of particles is a function of the delay time t. For a unimodal particle size distribution this fuction is a single exponential decay and can be represented by G(t) = 1+b exp(-t/tc), where b depends of the intensity of the light reaching the detector and tc is a characteristic decay time which can be related to particle diameter throughout Stokes-Einstein equation. Using this technique its possible to measure without previous calibration the particle size ranging from few nanometers to several micrometers.

In this work we prepare asphaltene and crude oils solution of Furrial (Venezuelans crude oils) in toluene in concentrations ranging from 800 to 80000 mg/L and induce the aggregation formation by addition of n-heptane. In this samples we measure the size of the particles presents in the solution at different proportions of n-heptane by using a home made DLS apparatus designed and optimized to work with dark and viscous solutions. Our results shows that for solutions without or low percentage of n–heptane added, small particles with dimensions of approximately 16 nanometers are present. This size of particles correspond to smaller expression of asphaltene aggregates, this results is in agreement with previous reports using different techniques (SAXS, SEM, etc). For solutions with more than 60% of n-heptane added two different particle size average appear, the first one correspondent for small particles ranging from 70 to 100 nanometers and a second of particle from 2 to 20 microns. These second groups of particles are flocs of medium size stabilized in the solution.

71 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 54

Characterization of the Onset Asphaltenes by Focused-Beam Laser Reflectance: A Tool for Chemical Additives Screening

Javier Marugán1,*, José A. Calles1, Javier Dufour1, Raúl Giménez-Aguirre1, José Luis Peña1,2, Daniel Merino-García2

1URJC-Repsol-YPF Flow Assurance Laboratory, Department of Chemical and Environmental Technology, ESCET, Universidad Rey Juan Carlos, C/ Tulipán s/n, 28933 Móstoles, Madrid, Spain 2Centro Tecnológico Repsol-YPF, Carretera N-V Km 18, 28931 Móstoles, Madrid, Spain. * [email protected]

Flow assurance problems caused by asphaltenes deposition are obviously related to the asphaltenes content of crude oils. However, the amount of solids determined by standard procedures (i.e. IP-143 standard) is not the only information required to predict the formation of deposits, as it does not provide any data about their stability. Probably, it is more important to determine the onset conditions in which asphaltenes start to flocculate, and the characterization of the physicochemical properties of the first solids, the onset asphaltenes.

This work deals with the study of asphaltenes aggregation kinetics near the onset using a laser reflectance technique (Focused-Beam Reflectance Measurement, FBRM). This tool provides a very sensitive way of determining the onset n-alkane/oil mass ratio. Influence of the n-alkane solvent and temperature on the solvent/oil threshold ratio of two South American crude oils with approximately 21 and 27 ºAPI respectively has been investigated. Moreover, the use of a FBRM technique provided kinetic information about the evolution with time of the size distribution of asphaltenes flocs.

For comparison purposes, additional FBRM experiments of asphaltenes redissolution- reprecipitation have been carried out starting from the solids recovered following the IP- 143 standard, which were fractionated into four different polarity groups using n- pentane:chloroform mixtures. The purpose was to look for correlations between polarity of the asphaltenes and its instability near the onset. Metal content has been determined through atomic emission spectroscopy and all the solids have been also characterized by 1H NMR, FT-IR spectroscopy, and vapour-pressure osmometry in order to elucidate the chemical and structural features of the most unstable asphaltenes.

Finally, we have used the FBRM probe for the screening of commercial chemical additives to prevent asphaltenes deposits. The results showed that this technique is a very powerful tool to investigate the influence of the additives on the aggregation kinetics and the particle size distribution of the first asphaltene solids.

72 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 55

Inorganic Solid Content Continues to Govern Water-in-Crude Oil Emulsion Stability Predictions

Michael K. Poindexter, Samuel C. Marsh

Nalco Energy Services, 7705 Highway 90-A, Sugar Land, Texas 77478

Solving oilfield emulsion problems is often addressed with the field bottle test. This widely used and informative method utilizes fresh samples and readily generates a number of emulsion stability parameters that aptly describe the diverse aspects of oil- water separation, namely water drop, oil dryness and interface quality. Bottle test data by itself is not predictive as all the parameters are dependent in nature. However, by coupling bottle test data with crude oil analyses, it is possible to gain insight into the factors which describe emulsion stability.

Past work using twelve different crude oils showed that inorganic solid content was the most informative parameter in describing emulsion stability. Higher solid levels result in more stable emulsions. Further field studies and laboratory analyses have doubled the size of the original data set. Statistical analyses of the expanded crude oil data set yield results that agree with the conclusions set forth in the original study. Inorganic solid content remains the most descriptive variable in describing all measures of emulsion stability. Several approaches were taken to examine the data. Both linear (multiple regression) and non-linear (partition tree) methods were used as were the mean and median values from the bottle test data.

73 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 56

An Investigation of Emulsion Interfacial Material by Ultrahigh Resolution FT-ICR Mass Spectrometry

Brandie M. Ehrmann1, Priyanka Juyal2, Ryan P. Rodgers1,2, Alan G. Marshall1,2

1 Department of Chemistry and Biochemistry, Florida State University, Tallahassee, FL 32306 USA 2 National High Magnetic Field Laboratory, Florida State University, 1800 East Paul Dirac Drive, Tallahassee, FL 32310-4005 USA

Production losses and the cost associated with chemicals used to break water and oil emulsions make emulsion formation a large problem for the petroleum industry. Therefore, it is advantageous to characterize and identify the species responsible for emulsion formation. It has been suggested that asphaltenes, the n-heptane insoluble but toluene soluble fraction of crude oil/bitumen, absorb and accumulate at the emulsion water-oil interface and contribute to emulsion stability. However, straight solvent drop methods used to extract asphaltenes from the parent oil have been shown to include a small amount of maltene material, or co-precipitate. Detailed analysis of the co- precipitant material reveals that it is highly enriched in acidic species that contain sulfur and oxygen. Thus, it is thought that the co-precipitated material may also contribute to the stability of the water/oil emulsions because prior FT-ICR MS analysis of the acidic portion of interfacial material reveals that it is also enriched in specific Ox and SOx species relative to the parent crude. The similarity between the co-precipitate and isolated interfacial material suggest that naphthenic acids interact strongly with the asphaltenes and as a result co-precipitate with them even though naphthenic acids (by themselves) are soluble in n-heptane.

Here we characterize the interfacial material and a crude oil known to cause emulsions in the field at an unprecedented level of detail. Positive/negative electrospray ionization and atmospheric pressure photoionization (APPI) high resolution FT-ICR mass spectrometry highlight the basic, acidic, and nonpolar (aromatic) species in the isolated interfacial material and parent crude. APPI results provide the first look into the individual nonpolar species (potentially the accumulated asphaltenes) in the interfacial material. We investigate the composition of the interfacial material and after isolation, attempt to regenerate the emulsion in the absence of the parent crude. Upon emulsion formation, analysis of the isolated interfacial material will confirm the minimum components necessary to form a stable emulsion. Isolation and subsequent analysis of the coprecipitant material provide a direct comparison between the species identified in the interfacial material and those that interact with the asphaltene fraction of the crude oil.

Work supported by NSF DMR-00-84173, Florida State University, and the National High Magnetic Field Laboratory in Tallahassee, FL.

74 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 57

Estimation of the Size of Asphaltene Aggregates Produced by Shear of Crude Oil

Lech Gmachowski, Maciej Paczuski

Warsaw University of Technology, Institute of Chemistry, 09-400 Plock, Poland

Aggregation of asphaltenes in the REBCO crude oil (Russian Export Blend Crude Oil) was investigated in a Couette device over a range of shear rate usually taking place in pipelines transporting the crude oil. After each experiment an amount of n-heptane was added to a crude oil sample taken and the sedimentation behavior of the obtained suspension was observed in a turbidimeter. A strong dependence was detected of that behavior on the concentration of the crude oil in the mixture.

Analyzing the sedimentation velocity (L. Gmachowski - Colloids Surfaces A: Physicochem. Eng. Aspects, 315 (2008) 57-60) of asphaltene aggregates and the mutual dependence between the sedimentation velocity and the turbidity (F. Gruy, M. Cournil – Part. Part. Syst. Charact., 21 (2004) 197-204) for different concentrations, the fractal dimension was deduced which is very close to that characteristic for diffusion limited process. This means that aggregates analyzed were formed during a secondary process induced by the addition of n-heptane, in which the aggregates produced earlier by shear of crude oil are monomers for the secondary aggregates.

Moreover, the shear rate influence on the settling velocity – turbidity relation is very weak, which can suggest that the size of asphaltene aggregates produced by crude oil shear does not change considerably with the shear rate.

75 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 58

Wax Deposition Measurement under Turbulent Flow Conditions for a Live Waxy Crude from Turkmenistan

Kamran Akbarzadeh1, John Ratulowski1, Tara Davies1, Rohaizad M. Norpiah2 1Schlumberger, DBR Technology Center, Edmonton, Canada 2Petronas, Malaysia

As production from conventional onshore and shallow water fields decline, deepwater production will continue to increase in importance. Cold temperatures and long offsets in deepwater production systems have introduced major flow assurance challenges that impact the flow of fluids from the well bore to the export line. One of the most pervasive flow assurance issues is the precipitation and deposition of waxy material due to the cold temperature environment.

Flow assurance considerations impact nearly all aspects of offshore system selection, design and operation. Representative laboratory fluid property and phase behavior data is key to input to develop designs and operating strategies that address flow assurance risks while minimizing both capital and operating costs. Conventional deposition testing for wax is usually run on dead oil in a low shear environment. However, in the production system, oil, gas and water are at elevated pressures and the flow regime is turbulent with high wall shear. Wax deposition data for dead oil taken under laminar flow conditions over predicts the actual wax deposition rates observed at field conditions.

In this work, a high-pressure deposition cell is used to study the deposition tendency of a waxy crude oil from Turkmenistan at field conditions. The impact of various design factors such as flow rate (or shear), temperature, and wax inhibitors on the wax deposition tendency is investigated. The effect of solution gas is also examined. Furthermore, a method for scaling the deposition cell data to pipe flow is presented and used in a multiphase flow simulator to predict the wax deposition profile in the field. The impact of using appropriate deposition data on system design and operation is discussed.

76 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 59

The Effect of Fluid Shearing and Wax Ageing on Wax Deposition in Pipelines

Susana Gómez Álvarez1, Tony Moorwood, SPE,2 Daniel Merino García1, José Luis Peña Díez1, Xiaohong Zhang2

1Repsol YPF 2Infochem

Wax deposition in pipelines is a major concern for the oil industry. Much work has been done to model wax deposition as measured by flow loops and other experiments. Models are routinely scaled up to predict the behaviour of full-scale pipelines, but little information is available to verify if such predictions are reliable.

A wax deposition model has been adopted that combines an accurate model for the thermodynamics of wax precipitation, a model for diffusive wax deposition based on mass transfer coefficients and a term for the removal of wax by shearing caused by the turbulence of the fluid flow. The wax is treated throughout as a fully compositional distribution of n-paraffins, because previous work has shown that simplifying the representation of the n-paraffins leads to results that appear to be physically unrealistic. The model has been shown to be in reasonable agreement with wax deposition rates reported from flow-loop experiments.

The paper describes the application of the wax deposition model to real pipelines. The shearing term is more significant in larger diameter pipes, and is needed to understand their behaviour. This is illustrated by reference to the operating experience of the Rodaballo sub-sea pipeline in particular. Even though the Rodaballo pipeline is below the wax appearance temperature, it has been successfully operated for several years without active wax remediation procedures. The deposition model is analysed to assess its agreement with the Rodaballo operating experience, and to assess under what conditions the pipeline could be considered at risk of blocking.

The paper considers the effect of wax ageing on the deposit. In cases where fluid turbulence may limit wax build-up, the wax deposit may gradually harden with time due to ageing. A hardening deposit could lead to long-term remediation problems. A number of possible wax ageing mechanism are considered, and how they would modify the deposition process. It is found that the effective diffusivity of hydrocarbon molecules inside the waxy gel deposit is a major uncertainty affecting the predictions. Model sensitivities are investigated in the light of this uncertainty; the possible impact of ageing on the Rodaballo pipeline is assessed.

In conclusion, the deposition model appears to be reasonably realistic as it combines a number of potentially dominant deposition mechanisms. The study suggests that predictions of wax deposition rates may be too high if shearing is ignored which could have important implications for remediation procedures. However, the study highlights the need for more information about actual wax deposition tendencies in full-scale pipelines.

77 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 60

Analysis of Acidic Compound Classes in Crude Oil by Negative Ion Electrospray Ionization High Resolution FT-ICR Mass Spectrometry

Priyanka Juyal, Ryan P. Rodgers and Alan G. Marshall National High Magnetic Field Laboratory, Florida State University 1800 East Paul Dirac Drive, Tallahassee, FL-32310-4005

Characterization of acidic constituents of crude oil is important due to the problems associated with those functionalities during production and refining. Acidic constituents are associated with the formation of stable emulsions during production, making efficient oil recovery and subsequent processing very difficult. Acid molecules in crude oil are primarily implicated for corrosion in refineries and pipelines. Corrosion by naphthenic acids and acidic sulfur compounds at high fluid velocity and high temperature during distillation causes breakdown of transfer lines, furnace tubes, valves and pump fittings. Naphthenic acids are also significant because of their surface activity and marginal water solubility, so that they may leach to wastewaters and cause adverse environmental effects. However, acidic components of oil are not limited to carboxylic acids but also molecules that contain sulfur and nitrogen. Tomczyk et al. report that one- half of the acidic species in a crude oil contain nitrogen and at least one-fourth sulfur (Energy Fuels, 15(6): 1498-1504, (2001)). The most pragmatic approach to understand the multitude of problems associated with acidic oil components and design better solutions is an improved understanding of the chemistry and physics of petroleum at the molecular level. We have previously reported applications of negative-ion electrospray ionization (ESI) Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) for speciation of acidic oil compound classes. Ammonium hydroxide is used in negative-ion ESI FT-ICR MS to deprotonate acidic species. It is a weak base because it gives a low concentration of hydroxide ions in solution. Molecules other than carboxylic acids may be only weakly or moderately acidic with high pKa values ranging from 9 to 34. Deprotonation efficiency of neutral or weakly acidic compounds is further diminished in the presence of carboxylic acids (matrix effect). Hence it is not easy to relate the observed ion relative abundances to those of neutral precursors in the original sample. We examine here the efficiency of quaternary tetramethylammonium hydroxide in speciation of acidic species in petroleum relative to ammonium hydroxide. The preliminary data is very promising in that this reagent allows us to ionize and detect species present at much lower concentration in the sample matrix. We demonstrate that a slight modification in the basic strength of the solvent system for negative-ion ESI- FTICR MS is extremely effective in generating a comprehensive compositional profile of crude oil acids over a wider DBE (double bond equivalents = number of rings plus double bonds to carbon) and carbon number range.

Work supported by NSF DMR-00-84173, Florida State University, and the National High Magnetic Field Laboratory in Tallahassee, FL.

78 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 61

Quantitative Molecular Representation of Asphaltenes and Molecular Dynamics Simulation of Asphaltene Aggregation

Edo S. Boek1, Tom Headen1,2, and Dmitry Yakovlev1,3

1Schlumberger Cambridge Research, High Cross, Madingley Road, Cambridge CB3 0EL, United Kingdom 2Dept. Physics and Astronomy, University College London, Gower Street, London, WC1E 6BT, United Kingdom 3DataArt, St.Petersburg, Russia Email: [email protected]

We have developed a computer algorithm to generate Quantitative Molecular Representations (QMR) of asphaltenes based on experimental data. Our work is based on the method of Sheremata [1] but has been extended in several ways. First, we generate molecular representations using a Monte Carlo method. For this purpose, we use an extensive set of aromatic and aliphatic building blocks, which are sampled randomly and then linked together using a connection algorithm. The building blocks are pre-fabricated for enhanced flexibility. We allow for both archipelago and peri-condensed structures to be generated. Then, we use a non-linear optimisation procedure to select a subset of molecules that gives the best match with experimental data. These experimental data consist of Molecular Weight (MW), elemental analysis and NMR spectroscopy, including both 1H and 13C data. First, we validate the method by testing a number of single model compounds. Then we use a real asphaltene data set available in the literature [1]. We generated sets of 5000 and 10000 samples, which were then optimized with respect to the experimental objective function. Different values of the MW were used as input parameter. It turns out that the objective function has a minimum for MW in the range 500 – 1000 g / mol. The optimal QMR asphaltene structures thus generated were then used as input in Molecular Dynamics (MD) simulations to study the formation of nano-aggregates.[2] We consider pairs of asphaltene molecules in an explicit solvent and constrain their centers of mass to specific separation distances varying from 3 – 15 Å. The average constraint force was measured to yield the Potential of Mean Force (PMF). It turns out that the free energy of aggregation is of the order of -8 kJ/mol, for both heptane and toluene as a solvent. This suggests that the formation of nano-aggregates is relatively independent of the nature of the solvent.

[1] J.Sheremata, M.Gray, H.Dettman and W.C.McCaffrey, Energy & Fuels 2004, 18, 1377-1384. [2] G.Andreatta, N. Bostrom, and O.C. Mullins, Langmuir 2005, 21, 2728-2736.

79 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 62

Could Naphthenic Acids be Responsible for Severe Emulsion Tightness for a Low TAN Value Oil? Part 1: Position of the Problem.

Vincent Pauchard1*, Johan Sjoblom2, Sunil Kokal3

1 Research and Development Center, Saudi Aramco, Dhahran, Saudi Arabia 2 Ugelstad Laboratory, Norwegian University of Technology, Trondheim, Norway 3 EXPEC Advanced Research Center, Saudi Aramco, Dhahran, Saudi Arabia * [email protected]

The particular emulsion stabilizing properties of a low TAN crude oil was analyzed with respect to the role of naphthenic acids. Previous investigations of this oil in PVT cells had provided the evidence of a severe increase in emulsion tightness with the pressure decay in the production system (tubing, well-head, pipeline). Due to the presence of a solid residue containing Calcium, Carbon and Oxygen, this phenomenon was first attributed to the precipitation of asphaltenes and calcite. Further investigations of the water chemistry and of the asphaltenes solubility recently led to the conclusion that another mechanism was involved. In addition, the elemental composition of the residue could match one of the calcium naphthenates. Furthermore, due to the presence of acid gases, the pressure decay in the production system is associated to a pH increase in a range known to be typical of organic acids related problems. Therefore, it was investigated how a low amount of naphthenic acids could lead to severe emulsion problems. Preliminary tests at atmospheric pressure with de-carbonated water showed that emulsion tightness significantly increased with pH, which confirmed the above assumption of a third mechanism. Then the organic acids were extracted from the oil using an Ion Exchange Resin and were characterized with respect to interfacial activity. It was found that these acids have a very high influence on interfacial tension at low dosage and exhibited most of the features observed with the so-called ARN tetra-acids first identified in deposits from North Sea fields. There was no analytical evidence of the presence of such acids in the oil. The conclusions were that the considered oil might contain a non-identified acids family prone to form a gel like layer at the surface of water droplets, therefore stabilizing the emulsion. These two aspects were investigated further as presented in the two associated papers (parts 2 and 3).

80 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 63

Systematic Study of Crude Oil-Rock-Clay Interactions Using a Quartz Crystal Microbalance

Adewunmi Abudu, Lamia Goual*

University of Wyoming, Department of Chemical and Petroleum Engineering Dept 3295, 1000 E. University Avenue, Laramie, WY 82071, USA Phone: 307-766-3278, Fax: 307-766-6777 * [email protected]

The purpose of this research is to perform a systematic study of Crude Oil-Rock-Clay (CORC) interactions using a Quartz Crystal Microbalance with dissipation factor (QCM- D). The QCM-D is a mass sensing device with the ability to measure, in real-time, very small mass changes on a quartz crystal sensor. The crystal sensor is mounted inside a flow cell and has a well defined relationship between its resonance frequency shift, dissipation, and mass deposited on its surface. The effects of liquid loading and trapping are both taken into account. Experiments are not limited to the availability of core samples and require very few amounts. To account for solid mineralogy, pure clay particles (kaolinite, illite, chlorite, and bentonite) are first utilized before considering more complex mixtures extracted from core samples. Similarly, model chemicals composed of pure acids and bases are first used to better understand the contributions of different chemical functions present in crude oils to CORC interactions. Tests are performed in a systematic manner where variables (crude and mineral compositions) are controlled. For each test, clays in toluene are first adsorbed on the crystal surface then exposed to organic solutes in toluene/heptane mixtures. Adsorption isotherms are recorded along with the viscoelastic behavior of the interfacial films. Each test depicts a characteristic behavior for a particular crude/mineral system in organic media. Results indicate different adsorption isotherms of crude oils depending on the clay type. The highest adsorption is recorded with kaolinite regardless of crude oil composition. This affinity is explained from the adsorption results with model chemicals. The findings of this work have direct implications to understanding wettability alteration due to asphaltene deposition.

81 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 64

Investigation on the Influence of Surfactants on the Wax Appearance Temperature through Rheological Assays

Afonso Avelino D. Neto2, Tereza N. de Castro Dantas1* Erika A. de Santana Gomes2, Eduardo Lins de Barros Neto2, Ranieri G. Ferreira Soares2

1Departamento de Química / 2Departamento de Engenharia Química Universidade Federal do Rio Grande do Norte Campus Universitário - CEP: 59072-970 – Natal – RN – Brasil *[email protected] / [email protected]

Petroleum samples containing normal-chain paraffins as major constituents are prone to difficulties in processing and transportation. Paraffin deposited onto the internal walls of pipelines drastically reduces the cross section area available for flow passage. Under the reservoir physical-chemical circumstances, the paraffin is dispersed in the petroleum samples as a solution. When the oil starts to flow to the surface, the thermodynamical conditions are usually changed, namely reduction in temperature, pressure and concentration of light hydrocarbons, which could otherwise help solubilizing the heavier fractions, hence enabling the formation of paraffinic crystals. The viscosity of paraffinic systems is an important parameter to be considered when designing equipments for oil pumping, reducing power consumption and increasing production. In this work, the following parameters that affect the formation of crystals have been examined: crystallization temperature, viscosity and density. The purpose was to acquire data which are necessary in the optimization of activities involving paraffin oils transportation. The experiments were performed with a synthetic paraffin solution (RLAM 140/145-1) and a petrochemical naphta solvent, both supplied by Landulpho Alves Refinery (Petrobras-Bahia- Brazil). Rheological data of the paraffin systems have been adjusted with the Bingham, Ostwald de Waale and Herschell-Buckley models. With the implementation of these models, viscosity values were quantified, relating their reduction with the crystallization temperature. All assays were carried out using paraffin (1, 3, 5, 7 and 10%) and the petrochemical naphta. In a subsequent step, the 10% paraffin concentration was selected in order to monitor surfactant effect on viscosity, when different concentrations of surfactant were used (1, 3, 5, 7 and 10%). During the assays, the samples were cooled from 40ºC to 15 ºC, under 5ºC intervals. A non-newtonian behavior is detected with paraffin systems. A more significant increase in viscosity for these systems occurred at the 10% paraffin concentration, at a temperature below 25ºC (the Wax Appearance Temperature, or WAT), due to the appearance of paraffin crystals. Upon addition of 1% of surfactant, a reduction of 41% in the viscosity was effected from 25ºC (WAT). With 3% and 5% surfactant, this reduction level was equal to 27%, and with 7% and 10% surfactant, the viscosity actually increased (higher surfactant concentration). It is important to point out that the viscosity is reduced at temperatures below the WAT, since it is in this phase that most operation problems related to the viscosity of paraffinic petroleum are encountered, due to crystallization. The presence of surfactant did not alter the WAT values, but caused changes in the viscosity. Therefore, provided that surfactants are used in low concentrations, further economical viability of their application to solve problems related to paraffinic deposits is guaranteed.

82 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 65

X-ray Photoelectron Spectroscopy and ToF-SIMS Analysis of Asphaltene Adsorption on Metallic Surfaces

W. A. Abdallah and S. Taylor

Schlumberger

Asphaltenes have received significant attention from both the upstream and the downstream petroleum industries, as well as from academia because of their propensity to damage formations, restrict pipelines, alter wettability, fouling, and further deactivate catalysts in the refining processes. Most investigations into asphaltene issues have focused on asphaltene colloidal and molecular properties (e.g., chemical structure and compositional analysis). Less attention has been paid to asphaltene molecular interactions and adsorption behavior since asphaltenes are complex structure. As a result, much is still unknown about the factors involved in asphaltene adsorption, which is the primary cause of formation damage resulting from blockage, and the effect on inorganic surfaces is believed to be primary cause for alterations in surface wettability.

The objective of this study was to examine and characterize the surface behavior of different asphaltene films on iron and stainless steel, two materials typically used inside petroleum pipelines and that are exposed to solids deposition. Tests were done to characterize the surface composition, chemical state, and depth profiling from the film surface to the asphaltene-metal interface. X-ray photoelectron spectroscopy (XPS) was used in conjunction with time-of-flight secondary ion mass spectroscopy (Tof-SIMS), both universal tools for surface characterization of solids. Both techniques are used to investigate the atomic surface concentration and chemical state of surface elements. The in-depth distribution of elemental composition in thin films was obtained by ion sputter depth profiling; a technique based on surface erosion that result from energetic argon ion bombardment.

Preliminary results using four different asphaltenes on the stainless steel surface indicated different atomic concentrations of C, S, N, and O but a similar chemical structure of their functional grouping as aromatic and aliphatic hydrocarbons. Both the XPS high-resolution binding energies and the highly sensitive ToF-SIMS analysis of the detected negative fragments of nitrogen and sulfur confirmed that the nitrogen compounds were pyrrolic and pyridinic, the sulfur was thiophenic, and the carbon was carboxylic and hydrogenated (C–O). The depth profiling found the surface to be carbidic after surface sputtering but showed no surface sulfur or nitrogen.

83 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 66

Charge Dependent Asphaltene Adsorption onto Metal Substrate: Electrochemistry and AFM, STM, SAM, SEM Analysis

N.Batina1,*, J.Morales-Martínez1, S.Ivar-Andersen2, C. Lira-Galeana3, W.De la Cruz-Hernandez4, L.Cota-Araiza4, M.Avalos-Borja4

1Universidad Autonoma Metropolitana-Iztapalapa, Laboratorio de Nanotecnologia e Ingenieria Molecular, 2 Technical University of Denmark, Dept. Hem. Eng. 3 Instituto Mexicano del Petroleo, Molecular Simulation Research Program, Lazaro 4 Universidad Nacional Autonoma de Mexico, *[email protected]

Formation of the molecular deposit onto pipeline walls is a principal cause of the plugging of the oil (petroleum) wells. Different kind of chemical analyses have identified asphaltens as the main component of the pipeline molecular deposit. Nowadays, it is obvious that better understanding of the mechanisms on the molecular deposit-pipeline interface, could be one of the key factor for solution of the asphaltene plugging.

Here, a set of highly sophisticated surface science techniques: Atomic Force Microscopy (AFM), Scanning Tunneling Microscopy (STM), Scanning Auger Microprobe Spectroscopy (SAM) and Scanning Electron Microscopy (SEM), were employed to characterized molecular deposits of the Mexican crude oil and asphaltenes, formed at the charged metal surface. The qualitative and quantitative characterization involved determination of size and shape of adsorbed molecules and aggregates (SEM/AFM/STM), and the elemental analysis of all components in molecular films (SAM/SEM-EDAX). Samples were prepared by the electrolytic deposition process under the galvanostatic or the potentiostatic conditions, directly from the crude oil or asphaltene in toluene solutions. Our results clearly show that formation of the oil and the asphaltene deposit depends on the metal substrate charge. In general, we found that asphaltenes as well as crude oil readily adsorb at the negatively charged metal surface. STM revealed that deposits consist of particular matter with average size of the 3 nm. The elemental analysis, probed by two independent methods: SAM for monolayer, and SEM-EDAX for the micron and above multilayers), revealed a presence of two elements: carbon and sulfur, which content ratio vary in dependence of the metal substrate charge. In same cases a successful analysis related to the elemental depth distributions along the molecular layer, was achieved. As result, we identified certain elements of the molecular deposit, in a preferential position, i.e. to be accumulated closer to the charged metallic surface. Taking into account that asphaltenes are conventionally the neutral type of molecules, the obtain results are interesting and surprising, i.e. the electrochemical studies show different adsorption behavior between two asphaltenes during the change of the electrode potential just for 100 mV. A possible mechanism of the charge influence onto formation of the asphaltene/the metal substrate interface will be discussed during presentation.

84 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 67

Adsorption of Petroleum Resins and Asphaltenes onto Reservoir Rock Sands Studied by Near Infrared (NIR) Spectroscopy

Rustem Z.Syunyaev1*, Roman M.Balabin1, Iskander S. Akhatov2

1Physics Department of Russian State University of Oil and Gas, 65, Leninsky Prospekt, Moscow, 119991, B-296, Russia 2Department of Mechanical Engineering and Center for Nanoscale Science and Engineering, North Dakota State University 111 Dolve Hall, PO Box 5285, Fargo, ND 58105-5285, USA *[email protected]

Asphaltenes and resins are the most polar petroleum macromolecules. It causes their rather high superficial activity. Interest to monolayer and multilayer adsorption of these natural macromolecules is mushroomed rapidly because of significant new opportunities. Relatively high value of asphaltene and resin adsorption means that these substances are responsible for many phenomena in petroleum industry: well bore plugging and pipeline deposition; stabilization of water/oil emulsions; sedimentation and plugging during crude oil storage; adsorption on refining equipment and coke formation. The knowledge of kinetic and thermodynamic parameters of adsorption opens an opportunity of regulation of capillary number and wettability. Actually it opens a way for physical and chemical engineering of liquid-solid interfaces in oil industry.

Adsorption parameters of petroleum resins and asphaltenes were evaluated by Near Infrared (NIR) spectroscopy. The bulk concentration changes during adsorption process. Experimental scheme of NIR-FT Spectrometer InfraLUM FT-10 (LUMEX, Russia), and its parameters are provided. NIR spectra range of 9000-13 000 cm -1 is chosen. Quartz, dolomite, mica and kaolinite sands (fractioned in own range each) were used as adsorbent. The particle size distribution was evaluated using optical microscope OPTITECH SME-F2. Porosity and permeability of each fraction were designed. Benzene is used as solvent. Different approaches of "NIR spectra-macromolecules concentration" calibration model building are discussed. Partial least squares (PLS) regression method is used. Langmuir model is chosen for experimental data fitting. Combined usage of kinetic and isothermic data gives us ability to evaluate the maximal adsorbed mass density, the equilibrium constant of adsorption, and the rate constants of adsorption (and desorption). The rate constants of resins adsorption and desorption are found to be concentration dependent.

The data obtained in this study are similar to the results on dye adsorption from water solution obtained earlier by laser refractometry. It is shown that these data can be modeled with and fitted to the “generalized Fick’s law of diffusion with relaxation.” The numerical algorithm for estimation of diffusion coefficient and relaxation time from the experimental data is developed.

85 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 68

Electrospray Ionization FT-ICR Mass Spectrometry of ‘ARN’ Naphthenic Acids in Crudes: Preconcentration and Quantification

Mmilili M. Mapolelo1,2, *, Ryan P. Rodgers1,2 and Alan G. Marshall1,2

1Department of Chemistry & Biochemistry, Florida State Univ., Tallahassee, FL 32306 2Ion Cyclotron Resonance Program, National High Magnetic Field Laboratory, Florida State University, 1800 East Paul Dirac Drive, Tallahassee FL, 32310-4005 *Speaker email: [email protected]

Many oilfield operators face flow assurance challenges associated with the deposition of naphthenate solids and formation of sodium soaps in production equipment. Calcium and sodium naphthenates are solid deposits and emulsions formed by the interaction of naphthenic acids with divalent (Ca2+, Mg2+) or monovalent (Na+, K+) ions in produced water. Calcium naphthenate formation is thought to depend largely on tetraprotic naphthenic acids known as "ARN" acids in the crude, whereas the formation of sodium naphthenate originates from less substituted lower molecular weight naphthenic acids. We present our first attempts to preconcentrate and quantify ARN-type acids in whole crude oils. The high resolution and mass accuracy of FT-ICR MS provide detailed acidic speciation for all crudes and deposits analyzed.

The preconcentration step was carried out by bubbling ammonia into toluene-diluted crudes known to have ARN-type acids. Use of ammonia to preconcentrate ARN acids in crudes effectively isolates ARN acids in the form of ammonium ARN acid crystals from a complex mixture such as crude oil. The crystals were isolated by simple filtration and reconstituted in negative-ion electrospray solvents (40:60 toluene:methanol) and analyzed by negative-ion ESI FT-ICR MS. ARN acids from the crystals increased from undetectable in the parent crude to the most abundant acid species in the extract mass spectrum. For quantitation, a "pure" ARN acid standard was prepared from successive cleaning and acid digestion of a naphthenate deposit. Analysis of the standard by negative-ion ESI FT-ICR MS showed only ARN acid species. Crudes and bitumen were spiked with the ARN standard at various concentrations to determine the broadband MS detection limit. To test the effectiveness of the ARN crystal extraction method, crudes were spiked with the ARN standard and then bubbled with ammonia to form the ammonium ARN acid crystals. We shall discuss how the crude oil composition (paraffinic vs aromatic), API gravity, and solvent systems may affect or influence crystal formation.

Samples were analyzed by negative-ion electrospray ionization (ESI) with a custom-built 9.4 Tesla FT- ICR mass spectrometer and the resulting mass spectral data were processed with an in-house data package (PREDATOR). FT-ICR mass spectra showed that the ARN acid standard has the potential to be used for quantification of ARN acids in crudes. Correlation of FT-ICR MS data of the respective crudes known to contain ARN acids naturally and crudes spiked with ARN acid standard will be discussed. We highlight the significance of the preconcentration step as a method to enhance the detection of ARN acids in crudes and consequently yield good quantitation.

Work supported by NSF DMR-00-84173, Florida State University, and the National High Magnetic Field Laboratory in Tallahassee, FL.

86 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 69

Effect Of Salts on the Interfacial Tension of Asphaltene-Toulene/Water Interface: Prediction by Poisson-Boltzmann Modified Model and Experimental Validation

R.A.G. Sé2,*, E.R.A. Lima2, M. Boström1, M. Nele2, F.W. Tavares2

1Department of Physics, Chemistry and Biology, Linköping University, SE-581 83, Linköping, Sweden. 2School of Chemical, Federal University of Rio de Janeiro, P.O. Box 68542, Rio de Janeiro, RJ, 21949-900, Brazil. *[email protected]

The understanding of the interaction of ions at the interface is of fundamental importance to the study of the stability of emulsions due to the presence of salts in production water. Due to the complexity of the interfacially active components in oil, it is simpler to use model systems consisting of asphaltenes dissolved in toluene. In this work, it is presented new experimental data of interfacial tension of toluene-asphaltene/water systems, in the presence of different salts. It was asphaltene of the Brazilian crude oil, precipitated with a 1:15 ratio of n-heptane and solutions of water with salts LiCl, KCl, NaCl, NaI, NaBr and KBr in concentrations of 0.10, 0.25, 0.50, 0.75 and 1.0 M. It was also investigated salt mixtures NaCl/NaBr and NaCl/NaI in the proportions 0.8:0.2, 0.6:0.4, 0.4:0.6, 0.2:0.8 molar. The experimental data were modeled using a modified Poisson-Boltzmann equation, which includes a term of image and another of dispersion, seeking a model capable of representing the influence of ions at the interface, following the Hofmeister series.

87 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 70

Atmospheric Pressure Photoionization Fourier Transform Ion Cyclotron Resonance Mass Spectrometry for Detailed Compositional Analysis of Petroleum

Amy M. McKenna1,2, Jeremiah M. Purcella, 1,2 Ryan P. Rodgers1,2, Alan G. Marshall1,2

1National High Magnetic Field Laboratory, Florida State University, 1800 East Paul Dirac Dr., Tallahassee, FL 32310-4005 2Department of Chemistry, Florida State University, Tallahassee, FL 32306

Fourier transform ion cyclotron resonance mass spectrometry’s inherent high resolution and mass accuracy make it well-suited for compositional analysis (at the level of molecular formula identification) of complex mixtures such as crude oil. Soft ionization techniques such as MALDI, field desorption, field ionization, electrospray ionization and atmospheric pressure photoIonization (APPI) have been applied to the mass spectral analysis of petroleum because they seldom produce fragment ions in the ionization process. However, conditions must be carefully controlled to avoid unwanted fragmentation that complicates an already crowded mass spectrum. Specifically, APPI is ideal for crude oil since it ionizes both polar (ie, pyridinic and pyrrolic nitrogen, carboxylic acids) and nonpolar species (ie, PASH’s, PAH’s, PANH’s) simultaneously. In APPI, vaporization of the analyte occurs by a heated inert sheath gas at adjustable temperature: advantageous for heavy end, high boiling crude oils because elevated gas temperature facilitates the vaporization of larger, highly aromatic compounds for subsequent ionization and mass analysis, and variable temperature spans the boiling point range of the sample analyzed. Thus, APPI FT-ICR MS analysis performed at discrete steps in sheath gas temperature provides a compositionally resolved measure of in-source distillation analysis of the crude. A bitumen HVGO distillation series was analyzed at a series of temperatures to determine the optimal nebulization temperature to sufficiently ionize the higher boiling species without thermal degradation of the lower boiling compounds. Detailed compositional analysis relates the two temperatures (i.e., nebulization and distillation cut) for composition dependent property prediction based on boiling point. To show that the MS-determined molecular weight distribution accurately represents a crude oil, two highly aromatic polycyclic hydrocarbon model compounds (boiling point, 595 °C and 770 °C, and molecular weight, 763 Da and 1531 Da) were analyzed by APPI FT-ICR MS over a range of sheath gas temperatures from 250 - 500 °C. The molecular weight of both compounds was verified by ultrahigh resolution FT-ICR MS with sub-ppm mass accuracy. MS/MS results were consistent with the structures of the synthetic standards. Surprisingly, the highest boiling cut of the distillation series as well as the high boiling standards were efficiently ionized and detected, even though the optimum sheath gas temperature fell well below their known boiling points. The applications to heavy end and asphaltene analysis as well as implications of the inherent thermal desorption limit of APPI sources will be discussed in detail.

Work supported by NSF DMR-00-84173, Florida State University and the National High Magnetic Field Laboratory in Tallahassee, FL.

88 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 71

Asphaltenes: Interfacial Aggregates Characterization and Film Structure

G. Alvarez1, J-F Argillier1, D. Langevin2

1Institut Français du Pétrole, 1-4 avenue de Bois Préau, 92852 Rueil-Malmaison Cedex, France 2Laboratoire de Physique des Solides, Université Paris-Sud, Bâtiment 510, 91405 Orsay Cedex, France

Heavy crude oil emulsions, which can be very stable, are a major problem in the exploitation of these strategic petroleum resources. Thus, a good knowledge of stability mechanisms of emulsions is a key factor for controlling and improving heavy oil production.Emulsion behavior is mostly controlled by the properties of the amphiphilic film that surrounds the droplets; in the case of crude oil its complex composition in terms of these molecules (asphaltenes, resins, naphtenics acids) makes difficult their comprehension.

In our study we combined several techniques as, measurements of dynamic interfacial tension and rheology of water and a model oil (toluene) interfaces in which asphaltenes or model naphthenic acids are dissolved, giving us information about mechanical properties of the films. Small-angle neutrons scattering (SANS) measurements, in which the structure of the interfacial layer and aggregates characteristics are obtained, as well as UV-VIS experiments that allowed us to determine the adsorbed asphaltene amount at the interface.

We show that different parameters such as model naphthenic acid/asphaltene ratio, molecular weight of the naphtenic acid, pH and ionic strength of the aqueous phase, have a strong influence on interfacial structure and film properties, and therefore on emulsions behavior. Stability tests on emulsions have allowed us to obtain some correlation between microscopic properties and macroscopic behavior.

89 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 72

Observations on Silicate and pH Control to Improve Separation of Water-in-Diluted Bitumen Emulsions Containing Clay Solids

Tianmin Jiang1, George Hirasaki1*, Clarence Miller1, Kevin Moran2

1Rice University 2Syncrude Canada Ltd. *[email protected]

Initial processing of Athabasca oil sands obtained from surface mining yields stable water-in-bitumen emulsions. When the bitumen is diluted with naphtha to reduce its viscosity and density, nearly complete separation can be obtained with a suitable demulsifier in the absence of clay solids. However, a rag layer forms between the clean oil and free water layers when clay solids are present. We show here that complete separation in this case can be obtained by (a) adding a small amount of sodium silicate during initial emulsion formation to make the solids less oil wet; (b) removing the clean oil formed following subsequent treatment with demulsifier and adding sodium hydroxide or sodium silicate with shaking to destroy the rag layer and form a relatively concentrated oil-in-water emulsion nearly free of solids; and (c) adding hydrochloric acid to break the oil-in-water emulsion.

90 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 73

Asphaltene Inhibitor Squeezing – What Can We Learn From Scale Inhibitor Squeezing?

Keith Allan*

Clariant Distribution UK Ltd *[email protected]

Scale inhibitor squeezing is a well defined process, in which the technology has rapidly developed over the last decade, both in terms of chemical development and placement techniques. Conversely squeezing of asphaltene inhibitor chemicals still seems to rely on a more "pump it and see" approach. In this poster we present some results of laboratory testing that has been performed on asphaltene inhibitors, where we have applied some of the principals and techniques used for scale inhibitor testing to show that selection of the best performing asphaltene inhibitor will not necessarily be the optimum choice for squeezing. Whilst performance testing with respect to inhibition is important, we also look at how these inhibitors adsorb and desorb onto rock surfaces utilising simple static adsorption tests, sandpack and full core flood test procedures. The results of this testing has allowed us to modify the chemistry of conventional asphaltene inhibitors to maximise their retention time in the reservoir and so potentially improve squeeze lifetimes.

91 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 74

Flow Assurance

Oliver C. Mullins1, Hani Elshahawi2, Chengli Dong1

1Schlumberger-Doll Research 2Shell Exploration and Production Company

Flow Assurance is an essential consideration for producing oil and gas particularly in high cost arenas such as deepwater. Many laboratory studies of phase behavior, sticking propensities, and interfacial interactions have been explored with regard to asphaltenes, wax, hydrates, organic and inorganic scale, and even diamondoids. However, one of the most important factors governing the magnitude of Flow Assurance problems has received scant attention – the spatial variation of reservoir fluids. In the past, it was often very difficult to address this issue in a systematic way due to cost constraints. With the advent of downhole fluid analysis, reservoir fluid variation and its impact on flow Assurance can now be considered at the outset. In this paper, we describe the origins and elucidation of reservoir fluid compositional variations. Certain controversies have arisen around these origins and are treated. The chemical analytical technology that is indispensable is described. We discuss the impact of these variations on Flow Assurance considerations and we show a methodology that accounts for these variations at the outset in Flow Assurance evaluation.

92 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 75

Characteristics of Wax Gel Formation in the Presence of Asphaltenes

Kyeongseok Oh*, Kaushik Gandhi, Pankaj Tiwari and Milind Deo

University of Utah, Chemical Engineering Department, Salt Lake City, Utah *[email protected]

Gelled waxy crude oils interrupt flow along pipeline facilities during the shutdown in cold environments. Restart requires that sufficient pressure is exerted to overcome the yield stress of gelled oils. The gel strength of the crude oils is determined primarily by Paraffinic components as the oil is cooled below the pour point. It has been also reported that asphaltenes play a significant role by depressing the pour point and causing lower yield stress values. In this paper, we examine the role of asphaltenes in the evolution of the yield stress as the oil is cooled below the pour point. A modified version of the vane method was used to measure the yield stresses at different temperatures. Yield stresses were measured at constant cooling rates and consistent holding times. Wax Appearance Temperature (WAT) and Pour Point (PP) were measured using the ASTM methods. Wax amounts with respect to temperature were measured using the Fourier Transform Infrared Method developed at the University of Utah. As the WAT and PP are dependent on wax amount and wax quality, this study examined the WAT and PP by comparing model oils with different wax compositions and different wax amounts. Yield stress values were strongly dependent on wax amounts and compositions as expected. The extent of increase in yield stress values was greater for model oils which had higher percentage of wax. The x-intercept values obtained from yield stress versus temperature were interpreted as no-flow points, which could be used as alternative measures of pour points. Yield stress increased linearly with decrease in temperature in asphaltene-free model oil. Asphaltene additions resulted in pour point reductions, of up to 40 C for additions of asphaltenes up to 0.1 wt%. Small amounts of asphaltenes (0.01 wt. %) also played a significant role in yield stress reduction. The magnitude of yield stress reduction at 0.01 wt% compared to 0.1 wt% indicates that steric hindrance and asphaltene aggregation are responsible for disruption of the gel formation. Also observed was a departure from the linear trend in yield stress versus temperature relationships with asphaltene addition indicating that the contribution of asphaltenes to the gel strength reduction is less pronounced at temperatures much lower than PP.

93 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 76

Assessment of Different Models to Describe Wax Precipitation in Flow Assurance Problems

C.Martos* , B. Coto, J.L. Peña1, J.J. Espada and M. D. Robustillo

Department of Chemical and Environmental Technology, ESCET, Universidad Rey Juan Carlos, C/ Tulipán s/n, 28933 Móstoles, Madrid, Spain.

1Alfonso Cortina Technology Centre, Repsol-YPF, E-28933 Móstoles, Madrid, Spain. *[email protected]

One of the most important problems in the flow assurance field is the deposition of paraffinic waxes present in crude oils. These compounds can precipitate when temperature decreases during oil production, transport through pipelines or storage. The accumulation of these solids on the walls can cause problems in pipelines and equipment and can lead even to stop production. Such problem is well-known within the petroleum industry and a big research effort is made to develop procedures to anticipate potential wax deposition problems.

The main variables involved in the description of the wax precipitation process are the wax appearance temperature (WAT) and the wax precipitation curve (WPC). Such magnitudes should be predicted by the available models1. However, the modeling of the precipitation process requires a good knowledge of the liquid-solid equilibrium involved and the scarcity of experimental information available limits the application of such models.

Therefore, new reliable experimental data are needed. The experimental information required to address wax precipitation and deposition is mainly related to the composition of the raw crude oil, the amount of precipitated waxes against temperature and the nature of such waxes2. Commonly, the application of the models available in the literature requires the knowledge of the n-paraffin distribution of crude oil. Such kind of determination can be carried out by different chromatographic techniques.

In this work, experimental WAT and WPC were determined by means of a multistage fractional precipitation procedure recently developed3. The trapped crude oil of the precipitated mixtures at each temperature was determined by 1H NMR technique and included to obtain the true amount of wax precipitated at each temperature. The n- paraffin distribution for the selected crude oils was determined by chromatographic techniques to apply different models.

Experimental and predicted results were compared to check the predictive capabilities of the available models.

References

(1) Coutinho, J.A.P.; Edmonds, B.; Moorwood, T.; Szczepanski, R.; Zhang, X. Energy Fuels. 2006, 20, 1081. (2) Martos, C.; Coto, B.; Espada, J.J.; Robustillo, M. D.; G?mez, S.; Peña, J.L. Energy Fuels. In press. (3) Coto, B.; Martos, C.; Peña, J. L.; Espada, J. J.; Robustillo, M. D. Fuel. In press.

94 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 77

Comparison of Crude Oils by Intrinsic Viscosity Studies in Different Solvents

Jan H. Beetge*, Jarrett J. VanderWilt Champion Technologies, Inc., 3130 FM RD. 521 Fresno, Texas 77545, USA *[email protected]

Intrinsic viscosity measurements are often done to determine the molecular mass or the hydrodynamic radius of polymers. This technique is also useful in evaluating the solubility parameters of a solute. The high molecular mass of most polymers allows sufficient sensitivity of typical instruments at dilute concentration. Most work is focused on single component systems, often with relatively narrow molecular mass distributions. It is perhaps the complex composition of crude oil, or the lower molecular mass of typical crude oil components, that limits the application of intrinsic viscosity in crude oil research. However, it is believed that the potential benefits or insights that could be gained, justifies the exploration of crude oil character by intrinsic viscosity techniques.

In this study, various crude oils were evaluated by intrinsic viscosity techniques, in a pragmatic approach to explore and compare the behavior of various crude oils. We were able to gather reliable data with low experimental error for most crude oils. Intrinsic viscosity, Huggins and Kraemer coefficients were calculated from relative viscosity measurements obtained using Ubbelohde capillaries at controlled temperatures. Experiments done in various solvents allowed the evaluation of solubility parameter on the behavior of crude oil in solution. The observed profiles of various crude oils were compared and discussed. An attempt was made to find correlations between the observations made in this study and other available data such as SARA analysis.

95 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 78

Role of Resins, Asphaltenes and Aromatics on Water-Oil Emulsions

C.Jones, P.A.Sermon, P.G.Skidmore and I.R.Collins

Chemistry, FHMS, University of Surrey, GU2 7XH, UK and BP Exploration, Sunbury, Middx, UK *[email protected]

Oil left within reservoirs after primary and secondary recovery can be trapped by capillary forces within the tortuous network of pores within the oil-bearing rock. Subsequent enhanced (or tertiary) oil recovery can be based upon CO2 flooding, alkaline flooding, steam injection and chemical flooding-with polymers and/or surfactants. Surfactants are only valuable if they are soluble in the aqueous phase at the reservoir temperature, salinity and pH, and are also only modestly adsorbed on the reservoir rock, but most importantly they must produce useful oil-water emulsions, phase equilibria, surface tensions and viscosities. With the correct choice of surfactant blend maximum additional oil-phase displacement can be achieved. The table below shows that the composition of middle phase emulsions formed with brine, 10wt% TX100, 10wt% 1- pentanol (ROH), 24wt% decane and 6% butylbenzene (BB) at 298K varies with the [NaCl] during a salinity scans: % con in middle phase 3 gNaCl/dm H2O ROH decane BB 10 75.25 8.88 12.55 3.32 20 61.71 12.71 20.26 5.31 30 55.26 13.25 24.87 6.64 40 51.59 14.54 26.72 7.13 i.e. the middle phase varies in oil content and and slightly in its aromatic: aliphatic component ratio. This can be explained by Winsor’s analysis of the relationship of interfacial structure, interfacial tensions and phase equilibria, and especially the effect of temperature on middle-phase III behaviour. In general aromatics have higher work of adhesions with water (Wo-w) than aliphatics:

alkanes 36-48 aromatic 63-67 and larger T dependencies for their interfacial tensions -dg/dT benzene 0.130 hexadecane 0.085

It is clear that replacing increasing the aromatic content of oil phases (e.g methylnaphthalene or butylbenzene (BB)) greatly affects the phase equilibria seen. In addition real crude oils contain a significant fraction of a wide range of alkenic and naphthalenic components. Furthermore, the asphaltene and resin constituents of crude oils are known to be surface active and to stabilise water-oil emulsions in oil well conditions thereby affecting the water- content in product flowing to the surface. Here the authors have considered how the aphaltene-resinous-aromatic content of crude oils affect the ease of formation of water-oil emulsions using GC-HPLC, phase equilibria, conductivity, optical microscopy and atomic force microscopy. The ratio of water to oil in the emulsions formed was found to depend on the proportion asphaltenes and resins in the oil; this can be used to ensure that the ratio reaches a plateau in production. The results presented with model crude oils are shown to be relevant to optimisation of oil production.

96 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 79

Dipole Moment of Asphaltene Nanoclusters

Syunyaev R.Z.*, Likhatsky V.V., and Balabin R.M.

Physics Department of Russian State University of Oil and Gas, 65, Leninsky Prospekt, Moscow, 119991, B-296, Russia *[email protected]

Aggregation of natural macromolecules - asphaltenes on nanoscale is one of key problems of the petroleum colloid science. Experimental studies of an estimation of energetic and kinetic parameters of structuring by various physical methods are rather numerous. At the same time methods of computer modeling are popular. Usually calculations are based on application of classical Lennard-Jones potential for nonpolar particles.

Consideration of dipole moment results in a number of singularities for aggregation processes. Monte-Carlo and Molecular Dynamics (MD) methods are used for estimation the dependence of dipole moment of nanoclusters from number of primary particles. Well-known Yen’s particle is accepted as primary. Quasispherical shape is result of stacking of flat aromatic fragments of asphaltene molecules. Asphaltenes concern to the most polar substances in structure of petroleum and have appreciable dipole moment. Earlier the attention was not attracted to this circumstance. Aggregation of those type particles becomes actual for analyzing the formation and evolution of petroleum dispersed systems.

Analytical solution within the framework of model of growing cluster at uniting with additional primary particle was received some time back. In approximation of continuous or drop asphaltene phase the power dependence of dipole moment of cluster from number of incorporated particles is shown. The fractal model of growth leads in Kohlrausch-Williams-Watts function.

The Monte-Carlo program complex allows simulating the aggregation process of dipole particles at following assumptions: · particles are spheres of specified constant radius in the course of simulation. · particles possess definite dipole moment randomly oriented in space · particles move freely until the moment of contact · at moment of contact the electric strength of growing cluster orients dipole of coming new primary particle according to the angle Boltzmann distribution. After sticking calculation of interaction between appeared cluster and next new particle continues · probability of joining particle to the cluster is independent from their interaction.

In MD method clusters appear owing to sticking primary particles after the certain number of steps.

Results of computer modeling confirmed power law obtained in analytical way. The model allows explaining the experimental results about abnormally large dipole moments of asphaltenes published earlier.

97 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 80

The Distribution of Polar Species in Athabasca Asphaltenes

Sara L. Salmon, David G. Zinz, Heather D. Dettman

CANMET Energy Technology Centre - Devon, 1 Oil Patch Drive, Suite A202 Devon, Alberta, Canada T9G 1A8

Molecular characterization of oil components is important for understanding and modeling petroleum behavior during production and refining processes. For those components with boiling point (bp) <524°C, gas chromatography (GC) can be used to separate species before analysis. For asphaltenes (bp>524°C) GC cannot be used but gel permeation chromatography (GPC) has proven useful (Dettman et. al. Energy & Fuels, 2005, 19, 1399-1404). Analyses of Athabasca asphaltene GPC fractions reveal that the asphaltenes consist of two types of species: “crunchy” (graphitic in appearance) and “oily”, with molecular weights from 400 to 2000 g/mole measured by low resolution mass spectrometry. Work has continued to separate the asphaltenes by polarity. Firstly, Athabasca asphaltenes were subfractionated into four parts based on differential solubility in pentane and centrifugation (Nalwaya et. al. Ind. Eng. Chem. Res 1999, 38, 964-972). Secondly, adsorption chromatography was used to isolate acidic species from the asphaltenes. The four “polarity” fractions and acid species were characterized including elemental and metals content and Fourier transform infrared (FTIR) and nuclear magnetic resonance (NMR) carbon type analyses. Their elution profiles by GPC were also compared.

98 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 81

Interface Behavior of Crudo Oil/Gas Systems in Function of Pressure and Temperature

Douglas J. Escalante Ayala1*, Vladimir León2

1 Laboratorio de Petróleo Hidrocarburos y sus Derivados, Departamento de Química, FACYT, Universidad de Carabobo, Venezuela. 2 Laboratorio de Biotecnología del Petróleo. Instituto de Estudios Avanzados (IDEA). Caracas-Venezuela. * [email protected]

The present work the values of interfacial tension in the system crude oil recombined/ methane were determined using heavy crude oil Venezuelans to conditions of reservoir, with the purpose of constructing experimental isotherms that describe the behavior of this parameter, since there are not data of interfacial tension in these systems. The measures were made by means of the pendant drop technique adapted to work to variable pressure and variable temperature. The crude oil analyzed were Cerro Negro, Zuata, Hamaca, Tía Juana and a medium Crude oil of the West of the country, all recombined to conditions of reservoir, in atmosphere of CH 4 to pressures from 1000 – 200 psi and temperatures of 40º - 80 ºC. Of the results obtained in this work, it is appraised a dependency between the superficial tension of the different systems crude oil recombined/gas studied with the pressure and temperature. The dependency with temperature of the superficial tension is the awaited one. The thermal expansion is reflected like a diminution of the superficial tension since it increases the surface, with the same interactions. The dependency with the pressure probably reflected an increase in the surface associated to the evaporated molecule balance. This effect takes to diminish the superficial tension with the pressure. That is to say, the rugosity is increased when increasing the number of molecular exposed in surface, which entails to an increase in the interactions associated by unit of geometric area giving like result an increase of the superficial tension. Also, the increase of pressure diminishes the rugosity and therefore the superficial tension.

99 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 82

The Distribution of Polycyclic Aromatic Hydrocarbons in Asphaltenes

Yosadara Ruiz-Morales,1,* A. Ballard Andrews,2 Oliver C. Mullins2

1Programa de Ingeniería Molecular, Instituto Mexicano del Petróleo, Eje Central Lázaro Cárdenas Norte 152, México D.F. 07730, México 2Schlumberger-Doll Research *[email protected]

The distribution of polycyclic aromatic hydrocarbons (PAHs) in asphaltenes has been a subject of significant controversy; yet is a powerful determinant for asphaltene physical properties. These PAHs also give rise to the UV and visible absorption and emission profiles of asphaltenes. All PAHs absorb light in the UV-visible without exception and many PAHs emit light in this spectral range as well. Here, we undertake a combined molecular orbital theoretical and experimental approach to quantitatively link the UV- visible absorption and emission profiles to the asphaltene PAH distribution. Major features of the absorption and emission spectral data are found to be reproduced with PAH distributions centered at seven fused rings. Other significantly different distributions of PAHs are discussed in terms of plausibility to account for the measured optical data. The influence of heteroatoms on the analysis is discussed.

100 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 83

Implications of Colloidal Phase Transitions on Reservoir Compartmentalization

Geza Horvath-Szabo

Schlumberger

The phase behavior of reservoir fluids is the single most important property for reservoir management. Based on pressure-volume-temperature (PVT) studies, much is known about the gas/liquid, liquid/liquid, and liquid/solid phase transitions in reservoir fluids. However, colloidal phase transitions have been overlooked by the oil industry. The colloidal properties of asphaltenes have been a focus of interest to the reservoir engineering community since O. C. Mullins and co-workers showed that the self- association of low molecular mass building blocks could lead to high molar mass aggregates. These associated species form a colloidal suspension in reservoir fluids. The sedimentation of these colloids results in a concentration gradient in reservoirs, which has recently been considered in reservoir descriptions. However, according to colloidal theory, a concentration threshold could be reached, where a phase separation would occur. To explain how this phase separation would occur, we studied phase transitions between colloidal-solid, colloidal-liquid, and colloidal-gas states. Although these transitions mimic the PVT phase transitions, we should describe them in the osmotic pressure (p) volume fraction (f), activity of the colloidal stabilizing/destabilizing compound (a) and the temperature (T) phase space. Considering the constancy of the total potential (i.e., external field and chemical potential) in thermodynamic equilibrium, we established a theoretical relationship between the osmotic pressure of a colloidal dispersion and its concentration distribution in a gravitational or centrifugal force field. We also developed a thin-layer analytical ultracentrifugation technique to measure the concentration distribution of colloids during rotation. Finally, we observed colloidal phase transitions in polystyrene suspensions for which we established the pfaT phase diagram as well. At the colloidal phase transition we found two suspensions with considerably different concentration in thermodynamic equilibrium. The external field does not impose the phase transitions; the centrifugal or gravitational field separates the already existing phases. We concluded that sharp composition changes of reservoir liquids do not necessarily mean reservoir compartmentalization.

101 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 84

Thermal Lens Technique to Evaluate the Fluorescence Quantum Yield of Asphaltene Solutions

Sergio Salazar, María Antonieta Ranaudo, Manuel Caetano* Escuela de Química, Facultad de Ciencias, Universidad Central de Venezuela, Caracas, 1040-A. *[email protected].

The fluorescence spectrum of asphaltenes obtained from venezuelan crudes is studied using an argon-ion laser as the excitation source and its fluorescente quantum yield (?f) is determined using a dual beam thermal lens method. The thermal lens effect is one of the thermo-optical methods usually employed for measurements in the very-low- absorption limit. This effect can be observed using moderate laser intensities in media with absorption coefficients as low as 10-7 cm-1. Formation of a thermal lens or thermal blooming occurs when energy absorbed from a Gaussian beam produces a local heating within the absorbing medium around the beam axis. In such experiments, the sample is exposed to a laser beam, with TEM00 mode, which has a Gaussian beam profile and causes excitation of the molecules along the beam path. Thermal relaxation of the excited molecules dissipates heat into the surroundings, thereby creating a temperature distribution which in turn produces a refractive index gradient normal to the beam axis within the medium. This acts as a diverging lens called a thermal lens (TL).

This is a nondestructive technique that gives the absolute value of ?f without the need for a fluorescence standard. The quantum-yield values are calculated for various concentrations of the solution in toluene. The values of ?f are relatively low, and concentration dependent. Stern–Volmer plots exhibit nonlinear behavior, indicating a possible complex quenching mechanism, probably influenced by the aggregation of the asphaltene molecules.

The aim of this work was to draw up an experimental and theoretical comparison of data provided by fluorimetry and thermal lens spectrometry and applied to the aggregation of asphaltenes.

102 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 85

Modelling Asphaltene Precipitation Equilibrium: Influence of the Experimental Contact Time and Temperature

Javier Dufour1 *, Javier Marugán1, José A. Calles1, Raúl Giménez-Aguirre1, José Luis Peña1,2, Daniel Merino-García2

1URJC-Repsol-YPF Flow Assurance Laboratory, Department of Chemical and Environmental Technology, ESCET, Universidad Rey Juan Carlos, C/ Tulipán s/n, 28933 M?stoles, Madrid, Spain 2 Centro Tecnol?gico repsol-YPF, Carretera N-V Km 18, 28931 M?stoles, Madrid, Spain. *[email protected]

Flow assurance problems due to asphaltene deposition cause high economic losses to petroleum companies. The use of predictive models is essential to prevent these problems. Several types of models can be found in the literature, most of them based on equilibrium calculations. For a reliable use of these models, they have to be checked against experimental data of both onset and amount of asphaltenes separated. Unfortunately, the kinetics of asphaltene aggregation and precipitation are slow, and the samples must be equilibrated for some time. Several of the protocols available in the literature (including IP-143 standard) do not allow obtaining true equilibrium data.

This work presents a discussion on the kinetics of asphaltene precipitation, based on results obtained with a South American crude and its 190+ Residue. This crude oil (31 °API) has been reported to give substantial operational problems due to asphaltene yield with time has been determined, in order to evaluate the time needed to reach the equilibrium. The influence of temperature, chain length of the n-alkane solvent and n- alkane / oil mass ratio has also been assessed. These solids have been characterized by 1H NMR, elemental analysis and FT-IR to determinate their chemical structure. Metal contents (mainly Fe, V and Ni) have been measured by atomic emission spectroscopy.

Once true equilibrium data have been obtained, they have been used to validate equilibrium models from the literature. SARA distributions have also been included with conventional experiments of total asphaltene yield (IP143 standard).

103 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 86

Modelling the Effect of Gas Injections on the Stability of Asphaltene-Containing Crude Oils

Xiaohong Zhang1, Tony Moorwood, SPE, 1 Daniel Merino García2, José Luis Peña Díez2

1Infochem 2Repsol YPF

Compared with some flow assurance issues such as gas hydrate or wax formation, asphaltenes are not such a common occurrence. However, for the fields where asphaltene deposits do occur, they present major remediation problems and can halt production altogether. It is usually believed that crude oils which precipitate asphaltenes contain both asphaltene molecules and lighter molecules termed resins. It is postulated that the resins solvate the asphaltene molecules thereby stabilising the solution. It is found that light gases have the opposite effect which can be seen from the position of the asphaltene deposition envelope (ADE) relative to the bubble point for crudes that show asphaltene precipitation. The lower branch of the ADE normally lies at pressures only slightly lower than the bubble point because, as the pressure drops below the bubble point, light gases vaporise from the oil resulting in a more stable asphaltene solution.

In many production situations, oil will come in contact with light gases. In the reservoir gas injection may be used, while in the wells or production facilities gas injection or fluid commingling may occur. Understanding the impact of adding gas to asphaltene- containing crudes is therefore an important aspect of modelling asphaltene phase behaviour.

A number of experimental studies of gas injection into asphaltene containing crudes is presented and the trends of asphaltene destabilisation are discussed. The injection gases range from pure gases to a gas condensate with an average molecular weight of 34. The data are modelled using a conventional equation of state combined with an extra term that represents the association between asphaltene molecules and their solvation by resins. The model has the advantage that it can simultaneously describe the gas, oil and asphaltene phases making it possible to calculate the phase stability and phase equilibria in general and consistent way. In comparison, the use of solubility parameters only allows the stability of the asphaltene phase to be calculated; a different model has to be used to obtain the gas-oil equilibrium.

The model correctly predicts that gases will promote asphaltene precipitation, but the model in its original form tends to over-predict the trend. The model sensitivities are examined in order to arrive at the optimal parameter values needed to represent all the available experimental data. Alternative mixing models are also investigated and the results compared.

In conclusion, the extent to which the effect of gas injection on asphaltenes can be predicted is discussed.

104 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 87

Formation and Aging of Deposits from Coker Vapours

Zhiming Fan*, Paul Watkinson Department of Chemical and Biological Engineering The University of British Columbia, Vancouver, Canada *Present address is: National Center for Upgrading Technology, #1 Oil Patch Drive, Devon, Alberta, Canada

Unwanted deposition of carbonaceous material from the vapour phase is a chronic problem in piping and equipment downstream of coking units and may be a limitation to achieving longer run length. In this work, the causes of deposit formation from vapours downstream of a lab scale coker were investigated via coke characterization with a range of techniques, to examine the evolution of deposit composition and structure over time. Laboratory deposits were compared with industrial samples, and a model of deposit structural evolution during the aging process proposed, based on kinetics of the deposit aging process and the above characterization results. Fresh and aged deposit samples recovered downstream from a bench-scale coker unit have been compared with samples from the snout and exit tube regions of a cyclone in an industrial fluid coker. Extensive characterization studies were conducted using elemental analysis, XRF, TGA, SEM, DRIFT, and Solid-state 13C NMR. Simulated distillation was also applied to solvent extracts of deposits. Results substantiate that physical condensation rather than chemical reaction is the primary reason for fluid coker cyclone exit line fouling. Entrained liquid droplets also contribute to the deposit formation to a lesser extent. Although the fresh laboratory deposits are much different from the industrial deposits, after days to weeks of aging at elevated temperature, the lab deposits become very similar to the graphitic industrial deposits. The differences in morphology which remain after aging, are attributed to the difference in hydrodynamic conditions during the deposit laydown. Kinetic models were developed to describe reactions in different aging periods based on thermal behavior of deposits recovered from the lab and industrial scale cokers. Deposit characterization and kinetic studies yielded a consistent picture of the evolution from the heavy fluid phase components which initially deposit from the vapour due to physical condensation, to the final massive, graphitic, coke-like solids found in industrial units. This structural evolution is described following the Marsh-Griffiths model.

105 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 88

Rheological Study of Athabasca Bitumen and Maya Crude Oil

MD. Anwarul Hasan1, Michal Fulem2,3 and John M. Shaw2

1 Department of Mechanical Engineering, University of Alberta, Edmonton, Alberta, T6G 2G8, Canada 2 Department of Chemical and Materials Engineering, University of Alberta, Edmonton, Alberta, T6G 2G6, Canada. 3 Institute of Physics, Academy of Sciences of the Czech Republic, v. v. i., Cukrovarnická 10, CZ-162 53 Prague 6, Czech Republic.

Heavy oil and bitumen are characterized by extremely high viscosity that negatively affects their upstream recovery, downstream transportation and refining processes. One of the key factors in facilitating the production and transportation is thus a better understanding of the origination of their high viscosity and the ability to reduce the viscosity to meet pipeline specifications (usually 0.4 Pa.s at operating temperature). The viscosity of heavy oil and bitumen and the structure of asphaltenes are linked to each other. It is known for decades that asphaltene content plays an important role in heavy oil and bitumen rheology with the general trend being that the viscosity increases with increasing asphaltene content. However, the influence of asphaltenes on viscosity has so far been studied on simplified samples where chemically separated (solvent extracted) asphaltenes are dissolved in some standard solvents or in the deasphalted oil (maltenes) to obtain reconstituted samples with different asphaltene concentrations. The question, how closely the nanostructures of such reconstituted samples resemble those arising in the original material remains unanswered in the literature. In this contribution, we report on the rheological properties of Athabasca bitumen and Maya crude oil along with their nanofiltered samples obtained by solvent-free nanofiltration (physical separation) and reconstituted samples prepared by mixing precipitated asphaltenes (chemical separation) and maltenes in different proportions. The rheological properties were studied over wide temperature and frequency ranges. The differences in rheological behaviour between nanofiltered and reconstituted samples, and the origins of these differences are discussed.

106 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 89

Solution Behavior of Naphthenic Acids and its Effect on the Asphaltenes Precipitation Onset

Carlos A. Carbonezi, Lucilla C. de Almeida, Bruna C. Araujo and Gaspar González

PETROBRAS Reseach Center, Av. Horacio Macedo, 950 - Cidade Universitária; CEP 21941-915, Rio de Janeiro, RJ, Brazil

Naphthenic acids represent a sub-fraction of the crude oil resins that contains predominantly carboxylic acids with saturated cyclic structures and correspond to a complex mixture of compounds with a broad polydispersity in molecular weight and structure. The increasing interest in naphthenic acids is due to the metal naphthenate precipitation that causes deposition problems in pipelines and production and treatment facilities. These compounds however play also an important role in limestone reservoirs wettability, crude oil foaming and emulsification, scaling, corrosion, etc.

The separation of naphthenic acids from crude oil would improve oil quality and would upgrade its market value. A physical-chemical characterization of these compounds would be very useful to assess the possibility of finding processes and procedures for this separation. In this contribution some aspects of the solution behavior of naphthenic acids are presented. It was observed that these compounds form stable liquid mixtures with organic solvents ranging from a solubility parameter of 14.4 to 29.7 (MPa)0,5 When added to partially soluble liquid mixtures like n-heptane-methanol they improve the mutual solubility of these liquids, increasing the solubility domain and partition into both liquid phases. In methanol-water mixtures NA are soluble up to a methanol concentration of approximately 81%. The precipitation onset for asphaltenes dissolved in toluene titrated with n-heptane was increased by the addition of naphthenic acids, indicating that these compounds contribute to the solubilization of asphaltenes representing a “good solvent” for this fraction. Applying the polymer solutions to the asphaltenes dissolved in liquid mixtures; treating the NA as a pure pseudocomponent and assuming that asphaltenes precipitation onset occurs at a particular solvents composition corresponding to a “critical solubility parameter” values from 24 to 26 (MPa)0,5 were obtained for the naphthenic acids.

107 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 90

Control of Hydrolysis of Emulsified Salts in Canadian Bitumens

Harmeet Kaur1, Paul Eaton2 and Murray R Gray1

1Department of Chemical and Materials Engineering, University of Alberta, Edmonton, AB T6G 2G6 2Champion Technologies Ltd, 3200 Southwest Freeway, Suite 2700, Houston, TX 77027

The bitumen from the oil sands can be contaminated with chloride salts like NaCl, CaCl2.2H2O and MgCl2.6H2O that originate from emulsified brines and process water. As the bitumen goes through the upgrading process, the salts undergo hydrolysis by steam to form highly corrosive hydrochloric acid and ammonium chloride. These reaction products give rise to corrosion and fouling of upgrading and refining equipment.

In order to investigate the role of bitumen constituents such as asphaltenes, the hydrolysis of salts was investigated in diluted bitumen, a bitumen/diluent/synthetic crude oil blend, and model oil. Different concentrations of emulsified salts were added and the samples were steamed at 150-350 °C to drive the hydrolysis reaction. A 10% solution of mixed salts (70 wt% NaCl, 20 wt% CaCl2.2H2O and 10% MgCl2.6H2O) in water was added to the oils in order to simulate oilfield brines. The vapors from the hydrolysis process were condensed and collected, then analyzed by ion chromatography. Selected experiments were run with inhibitors to prevent the release of chloride from the crude oils.

Increasing the concentration of salts in the diluted bitumen from 76 ppmw to 500 ppmw, was found to increase hydrolysis and percentage of chloride released, from 0.4% to 10% respectively, of the total chlorine in the sample. Surprisingly this blend gave only 0.4% chloride release from the base chloride content of 76 ppmw. The three-way blend of bitumen with diluent and synthetic crude, with a chloride content of 53 ppmw, gave 0.9% chloride release from the base sample and 10% chloride release from added salt at 500 ppmw, then decreasing to 5% release of chlorides. Although the heavy blends gave different trends of % release as a function of salt concentration, both gave the same maximum percentage release of chloride of circa 10%. Experiments with pure salts in a model oil and the three-way blend showed complete conversion of MgCl2.6H2O in all cases, and low conversions of NaCl. The conversion of CaCl2.2H2O was much higher in the crude oil than in the model oil. These data suggest that naphthenic acids, clay minerals, and possibly asphaltenes may play a role in the hydrolysis reactions. The addition of inhibitors reduced the release of chlorides by as much as 94% depending on the crude oil.

108 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 91

A QCM Technique to Quantify the Gas Solubilization in Oil.

J. Pauly1,*, M. Cassiède1 , J.H. Paillol2, I.M. Marrucho3, J.A.P. Coutinho3, J.-L. Daridon1

1 Laboratoire des Fluides Complexes – UMR 5150 – B.P. 1155 – 64013 Pau Cedex, France 2 Laboratoire de Génie Electrique – Hélioparc Pau-Pyrénées – 64053 Pau Cedex 9 3 CICECO – Universidade de Aveiro – 3810–193 Aveiro, Portugal *jerome. pauly@ univ-pau.fr

A quartz crystal microbalance technique has been developed in the Laboratory of Complex Fluids in Pau University to measure the solubilization of gases in heavy crude oils. Due to the increasing demand for oil and to face the depletion of natural resources, Petroleum Industry has resorted to exploit non-conventional oil fields, and particularly bituminous sands. Some technologies such as hot vapour or carbon dioxide injections are being developed in order to decrease the viscosity of these extra-heavy oils and thus make their extraction easier. Unfortunately, the solubilization of gas in heavy crude oils is very slow. To quantify the impact of the gas addition on the phase behaviour, it is necessary to develop laboratory experiments and to work on very small samples to increase the kinetics of the processes.

The QCM developed allows to work with pressures up to 100 MPa in a range of temperature from 243.15K to 403.15 K. The experimental device is composed of a thin quartz strip sandwiched between two electrodes and it is based on the piezoelectric effect. By applying an alternative current to the quartz, it is submitted to periodic mechanical stress and ultrasonic waves appear. Consequently, the crystal starts resonating and oscillates at a frequency depending on the quartz thickness. According to Sauerbrey, a relation of proportionality links the frequency changes to the variation of the deposited mass on the quartz. Mass shifts of about 1 nanogramme can be detected. To correct the influence of pressure and temperature on the frequency, a second non- coated quartz crystal is used as a reference in the autoclave cell.

With this experiment we are able to determine the solid-liquid-vapor three-phase equilibrium the melting temperature of pure n-alkanes in the presence of gas under high pressure.

Characterization of the behaviour of extra-heavy crude oils is also possible but the deposited film has to be considered as a viscoelastic one leading to the impossiblility to get the material properties by only measuring the frequency. Therefore, the acoustic conditions on the surface of the quartz can be obtained by the determination of the impedance spectrum of the quartz around its resonance frequency.

109 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 92

Evaluation of Hydrotreating Reaction Time of Furrial Crude Oil for Improvement of Asphaltene and Their Fractions in p-Nitrophenol

Miguel Angel Luis1*, Yanet Villasana1,2, Henry Labrador2

1Laboratorio de Catálisis y Metales de Transición. Departamento de Química, Facultad Experimental de Ciencias y Tecnología, FACYT, Universidad de Carabobo,Estado Carabobo. Venezuela. 2Grupo de Petróleo, Hidrocarburo y Derivados (PHD), Departamento de Química, FACYT, Universidad de Carabobo, Estado Carabobo. Venezuela. *[email protected];[email protected]

In this work, the hydrotreating (HDT) reaction time of Furrial crude oil using NiMoS/g- Al2O3 as catalyst for improvement of asphaltene and their fractions (A1 y A2) obtained by p-nitrophenol method, was evaluated. The reaction conditions were: temperature: 310ºC, pressure (H2): 70bar, 240rpm of stiring, 300mg of catalyst and 50mL of Furrial crude oil at different reaction times: 6, 8, 10 y 24 hours using a batch reactor. Two hydrotreating reactions without catalyst at six and eight hours at the same conditions were made, due to compare the effect of the catalyst presence on the asphaltene. Finally, two reactions more variating the catalyst were carried out. The first catalyst results of the mechanical mixture of nickel and molybdenum sulphides supported on g- Al2O3 by incipient impregnation method, and the second, results of the mechanical mixture of bulk sulphides obtained by homogeneous precipitation method with amonium sulphide ((NH4)2S); due to study the catalyst synthesis effect. The asphaltene hydrotreated was precipitated with n-heptane, and later was fractionated employing p- nitrophenol method (PNP), obtained two fractions, one insoluble fraction in toluene (A1) and another soluble fraction (A2). The asphaltene obtained of each reaction and their 13 fractions A1 and A2, were characterizated by nuclear magnetic resonance (NMR) C, elemental analysis of C, H, N and S, like as toluene solubility and floculation threshold (FT). It was observed that the optimum reaction time was six hours, obtained an asphaltene so stable as the original, predominantly aliphatic with less nitrogen and sulphur contents. Furthermore, the synthetic catalyst not improve to comercial catalyst,

NiMoS/g- Al2O3. The hydrotreating reactions without catalyst not improve the asphaltene characteristic.

110 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 93

Investigation of Heavy Petroleum Oils From Different Refineries by Group-Class Characterization

Maria Helena G. Pereira1*, Fabio F. Pereira1, Alexandre T. de Castro1 Luiz D. de Castro1, Ricardo C. Michel2

1 Department of Carbon Materials Technology, Centro Tecnológico do Exército – Avenida das Américas, 28705 Rio de Janeiro 23020470 Brazil 2 Instituto de Macromoléculas – Universidade Federal do Rio de Janeiro – UFRJ Brazil * [email protected] Pitches produced from petroleum catalytic cracking residue (FCC decanted oil) are currently used as raw material in the manufacturing of high technological and sophisticated carbon materials such as high density graphites, pitch carbon fibers and carbon-carbon composites. The properties of these end-products are closely related with the chemical composition of the initial precursor. Therefore, the characterization of these aromatic residues is a key issue to select the ideal parameters towards the production of a pitch suitable to melt-spinning and to identify the properties which will determine the quality and performance of the end products. The hundreds of individual compounds constituting petroleum residue and related materials vary in molecular structure, size, polarity, functionality and chemical and thermal reactivity. Generally, these compounds belong to distinct classes of hydrocarbons: polyaromatic (PAHs), alquilated, naphthenic and heterocyclic containing oxygen, nitrogen or sulfur. The overall composition of a given decanted oil as well as the quantity of a specific family depends on the type of material and its thermal processing history. The bulk properties of these oils such as elemental composition, density, aromaticity, carbon value and viscosity are normally used as characterization parameters. However, materials with similar bulk properties may have different behavior during thermal treatment. Petroleum heavy distillates (decanted oils) from distinct refineries were fractionated by extrography to obtain four fractions of crescent polarity determined by a sequence of solvents. An alteration of the usual procedure was proposed to improve the separation of the fractions and avoid overlapping. Fractionation was analyzed by Gas Chromatography coupled with Mass Spectrometry (GC-MS) and Fourier Transform Infrared Spectroscopy (FTIR). The fractions obtained were saturates, neutral aromatics, neutral nitrogen heterocompounds and polar sulfur, oxygen and nitrogen compounds. A good selectivity was achieved as confirmed by mass spectrometry, showing the suitability of the technique for the characterization of petroleum materials.

111 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 94

Could Naphthenic Acids be Responsible for Severe Emulsion Tightness for a Low TAN Value Oil? Part 2: Interfacial Rheology.

Patrick Bouriat1,*, Vincent Pauchard2, Christophe Dicharry1

1Laboratoire des Fluides Complexes, UMR CNRS 5150, Université de Pau, BP 1155, 64013 Pau Cedex, France 2Research and Development Center, Saudi Aramco, Dhahran, Saudi Arabia *[email protected]

Interfacial rheology of a water/crude oil system was investigated with an oscillating pendant drop tensiometer at different pH and water salinities. The considered crude oil has a low TAN value but behaves like acidic oils (part 1).

For low salinity solutions (de-ionized water with addition of strong acid or basis), the rheological behavior was close to that of a Hookean solid with small variations of elastic modulus with frequency and low loss angles. Elastic modulus decreased with increasing pH, suggesting that the interfacial layer became less packed due to electrostatic repulsion between the adsorbed ionized surfactants (RCOO-).

For brines, the rheological behavior corresponded to that of an interfacial network at its percolation point, which allowed characterizing the interface in term of gel strength and power exponent. While the power exponent was roughly constant around 10 degrees, the gel strength varied significantly with the pH value and composition of water. For a given salinity, gel strength strongly increased when pH increased. This ranking of gel strength with pH was found to be the same as the one of water separation kinetics obtained with a Turbiscan apparatus. For a given pH, gel strength was maximal with sodium brine and minimal with calcium brine. This ranking was again confirmed by the one of water separation kinetics. In the presence of sodium, the interfacial layer was most certainly compacted due to the screening by Na+ of the repulsive electrostatic force between ionized surfactants. In the presence of calcium, the bonding of two adsorbed surfactants by each Ca2+ probably created conformational constraints in the interfacial layer, which added some organization but penalized packing. This analysis is supported by the fact that experiments with Ca2+ exhibited the highest interfacial tension and the best fit between loss angle and power exponent.

The overall conclusion of this rheological study is that the various effects of salts on the water/oil interface allow for the formation of a gel like layer, primary by entanglement of very packed surfactants and secondary by cross-linking of surfactants. These results find some explanations in the analytical results presented in part 3.

112 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 95

Could Naphthenic Acids be Responsible for Severe Emulsion Tightness for a Low TAN Value Oil? Part 3: Analytical Chemistry.

Vincent Pauchard1, Hendrik Muller1*, Adnan al-Hajji1, Ryan Rogers2 1Research and Development Center, Saudi Aramco, Dhahran, Saudi Arabia 2Florida State University, USA *[email protected]

The detailed composition of a low TAN crude oil causing severe emulsion problems (see related papers part 1 and 2) was studied by means of Fourier Transform Ion Cyclotron Resonance Mass Spectrometry (FT-ICR-MS). The detailed compositional analysis of the whole crude revealed unusually high amounts of oxygen containing ringed hydrocarbons. Then the characterization of the organic acids as extracted by Ion Exchange Resin Chromatography revealed two classes of acids. Firstly, the classical acyclic fatty acids. Secondly, mono- and bi-protic acids containing numerous naphthenic and aromatic rings, with a molecular weight ranging from 250 to 750 Da. Finally, the whole crude oil and the extracted naphthenic acids were compared to the interfacial material as extracted from an indigenous water/oil emulsion collected in the production stream. A first extraction step used toluene as a solvent to remove the species physically adsorbed on the interfacial layer in contrast to the interfacial material, which is chemically bonded to the water surface. The physically adsorbed material was composed primarily of the common set of acids present in the oil (both fatty and cyclic) and secondarily by asphaltenes. The second extraction method was designed for naphthenate deposits: a sample of emulsion was put in contact with both strong acid and toluene to protonize naphthenic salts into free acids. The result was similar to the sets of fatty acids found elsewhere in sodium naphthenate deposits and differed from the ARN acids found in calcium naphthenate deposits. These findings may explain the observations presented in the two associated papers. It is believed that the synergistic effects between fatty acids and multiply ringed acids in association with an aromatic structure in some acids create a multi-layered interface with particular properties. The fatty acids are probably bound to cations at the water surface and are acting as anchors for physical entanglements with other acids that are present either under the free acid or the salt form. A low molecular mobility of these other acids (due to their multiply ringed structure) offers an explanation for the efficiency of the entanglement. The overall result is a gel-like interface acting as a solid shield against droplet coalescence.

113 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 96

Colloidal Analysis of the Asphaltene and Their Fractions With p-Nitrophenol (PNP) of the Furrial Crude Oil for Effect of the Hydrotreating to Different Pressures

Henry Labrador-Sánchez1*, Lenin Lindarte1, 2, Miguel Ángel Luis2

1Grupo de Petróleo, Hidrocarburo y Derivados (PHD), Departamento de Química, Facultad Experimental de Ciencias y Tecnología (FACYT). 2Laboratorio de Catálisis y Metales de Transición. Departamento de Química, FACYT, Universidad de Carabobo, Estado Carabobo. Venezuela. *[email protected]

In this work, the effect of the hydrotreating (HDT) to the Furrial crude oil on the asphaltene and their fractions A1 and A2 obtained by the p-Nitrophenol (PNP) method [1] was studied. Eight HDT reactions were carried out to the Furrial crude oil using a batch reactor, to different pressures of hydrogen (70, 85, 100 and 120 bar). After the reactions, it was separate the asphaltene of the crude oil, which was fractioned with PNP being obtained A1 and A2. The asphaltene and their fractions were characterized for: flocculation threshold, percentage (% ) of total sulfur, nuclear magnetic resonance of 13C and elemental composition. With the results obtained it was found that the HDT affected the colloidal behavior of the asphaltene, it was determined that the presence of the catalyst favored the conversion of the asphaltene, its stability, and its desulfuration, the relationship Caliphatic/Caromatic what suggests increased that the process of HDS you takes for two mechanism, above the 100 bar the stability is not favored of the asphaltene, giving us that the interval of pressure is between 80 and 100 bar, under the reaction conditions. The HDT affected in more proportion the fraction A2 than A1 indicating us that the fraction is susceptible to the reactions of HDT, due that is in the periphery and the A1 it is located in the pith[2] being the less reactive one. The percentage of total S indicate that the fraction A1 should be more poliaromatic, and with the percentages m/m of the fractions of PNP it was found that the fraction A1 always had the biggest value.

[1] Gutierrez, L.; Ranaudo, M.; Méndez, B. And Acevedo, S. Energy Fuels, 2001, 15, 161-175. [2] Acevedo, S.; Rodríguez, P. And Labrador, H. Energy Fuels, 2004, 18, 1757- 1763.

114 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 97

Equivalent Alkane Carbon Number (EACN) of Oils and Solvents and Characteristic Curvature of Naphthenic Compounds.

Sumit Kiran1, Kevin Moran2, and Edgar J. Acosta1

1University of Toronto, Department of Chemical Engineering and Applied Chemistry 2Syncrude Canada Ltd.

In surfactant-enhanced oil recovery, the hydrophobic nature of the oil phase can be characterized by the equivalent alkane carbon number (EACN) of the oil. This parameter is obtained after determining the optimal formulation (typically electrolyte concentration) that yields ultralow interfacial tensions. While the EACN of a paraffin is simply equal to the number of carbon atoms in its molecule, the same can not be said about aromatic oils. In the case of benzene, for example, its EACN is zero. In this presentation we will discuss our latest efforts in determining the EACN of bitumen samples, asphalt samples and model molecules using simple phase behaviour scans of mixtures of toluene with these oils. The method reveals that asphalthene-rich fractions have relatively low EACN when compared to their carbon content, which is consistent with the interfacial activity of these fractions. In addition, the phase behaviour of “reference” microemulsions produced with sodium dihexyl sulfosuccinate and toluene can also be used to determine the characteristic curvature of naphthenic acids and naphthenates. The characteristic curvature of a sample of sodium naphthenates reveals that naphthenates can be as hydrophilic as sodium dodecyl sulphate. The potential impact of these findings in petroleum phase behavior and future applications of this methodology are discussed.

115 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 98

Application of Microemulsion Systems in the Desorption of Heavy Petroleum Fractions

Tereza N. de Castro Dantas1*, Afonso Avelino D. Neto2 Diego A. Araújo Gomes2, Alexandre Gurgel2, Cláudio R. Santos Lucas2

1Departamento de Química / 2Departamento de Engenharia Química Universidade Federal do Rio Grande do Norte Campus Universitário - CEP: 59072-970 – Natal – RN – Brasil *[email protected] / [email protected]

Crude petroleum is a highly stable, dispersed, colloidal system comprising a few heavy constituents (asphaltenes, resins, waxes, etc), with different molecular wieghts, which are responsible for occasional precipitation of an asphaltic material denominated as sludge. This phenomenon occurs in completion and stimulation operations, due to contact between the formation oil with the fluids used as recovery agents, provoking problems related with well production, transport in oil pipelines and refinery operations. Microemulsions are presented as highly stable systems with low viscosity and formed spontaneously, featuring optical isotropy and high solubilization capacity. These properties are responsible for their versatility, enabling their application in several technological activities. In view of all this, the present investigation was carried out with the purpose of examining the ability of microemulsion systems to solve problems encountered in processes of petroleum production, particularly the solubilization of heavy petroleum fractions which ultimately induce solid sludge formation. The first part of the work focused on the construction of typical phases diagrams, aiming to establish the best composition conditions to prepare the systems. The following four mixtures were tested: Surfactant UNTL 90 + Butan-1-ol + Water + Xylene; UNTL 90 + Butan-2-ol + Water + Xylene; UNTL 90 + Butan-1-ol + Water + Kerosene; UNTL 90 + Butan-1-ol + Water + Mixture of Kerosene:Xylene (9:1 in volume). In parallel, physical adsorption static assays were performed aiming to mimic the natural reservoir conditions. The tests were carried out with asphaltic residues from the drilling sites, xylene as solvent and Assu (Rio Grande do Norte State, Brazil) and Botucatu (Paraná State, Brazil) arenite samples as rock reservoirs. The adsorption curves were ascribed the “S” pattern, according to the classification proposed by Giles et al. (1974). This type of isotherm is presented in terms of a cooperative adsorption phenomenon, featuring an inflection point that defines the concentration where adsorption overcomes complexation events. Batch desorption processes were executed and the microemulsions were used as extracting agents. Preliminary experiments have indicated that the systems containing kerosene as organic phase did not present satisfactory efficiency yields due to difficulties in the flow across the porous medium resulting from the high viscosity of the oil-microemulsion mixture. The extraction efficiency of the systems containing xylene was higher, a result of the enhanced solubilization capacity of aromatic solvents and broader microemulsion regions detected in the phases diagrams. It is expected that this work contributes to the diversification of microemulsion applicabilities in solving problems involving handling of petroleum products, especially in the prevention of sludge formation.

116 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT - 99

X-Ray Diffraction of Asphaltenes Heptol Sub-Fractions From a Brazilian Vacuum Residue

Lina Constanza Navarro Quintero 1,*, Peter Rudolf Seidl 1, Juan Carlos Poveda2, Álvaro Saavedra3, Sonia M. C. Menezes 3, Ljubica Tasic 4, Katia Z. Leal 5.

1 Escola de Química, Universidade Federal do Rio de Janeiro 2Universidad Autónoma de México; 3CENPES, Petrobras 4 Instituto de Química, Unicamp; 5 Instituto de Química, UFF. Brazil * [email protected] In the petroleum industry it is well-known that the asphaltene fraction or part of its constituents can cause problems. These problems are attributed to the tendency of asphaltenes to flocculate and precipitate during both oil production and refining. In production they can reduce oil flow or even obstruct pipelines while in refining they may be responsible for severe limitations in processing of heavy fractions due to the tendency to form coke, catalyst deactivation, and poisoning. [1]. The need for a more efficient utilization of heavy petroleum fractions has stimulated interest in elucidating the molecular structure of asphaltenes. A better knowledge of the chemical structure of this class of substances is the key to understanding their behavior in different stages of petroleum processing.

In the present work, X-ray diffraction is applied to different asphaltene fractions in order to better understand the way in which they aggregate. Asphaltene fractions were obtained by precipitation from vacuum residues using mixtures of heptane and toluene (Heptol) in different concentrations, as precipitation solvent. Our recent work [2], evidences important differences between distinct asphaltene sub-fractions and reveals that aromatic species with higher content of ring fusion aromatic carbons can concentrate in a specific sub-fraction. It is noteworthy that it is not the least soluble fraction.

X-ray diffraction analysis indicated that differences between the asphaltene before fractionation and the different asphaltene sub-fractions are very minor. The patterns of the samples show that most of them present broad contributions around 2q = 20°, 25°, and 44°. Different interlayer distances (dm) were calculated and for all the samples present a dm range around 3.4Å. The interchain layer distance (dg) is between 4.4 and 4.5Å, and the diameter of the aromatic clusters is perpendicular to the plane of the sheets (Lc) ranging between 26.8 and 30.7Å; in agreement with recent literature [3,4]. Aromaticity calculated from classical XRD [3] gave values between 0.1 and 0.2; in the same range as XRD asphaltene parameters reported in others studies [3, 4], but in disagreement with aromaticity calculated by NMR or elemental analysis [2]. Finally, according to X-ray data, an average of 8 asphaltene molecules in each asphaltene aggregate was estimated.

[1] Speight, J.; Long, R. Fuel Sci. Technol. Int. 14, p 1, 1996. [2] Navarro, L. C.; Seidl, P. R.; Tasic, L.; Leal, K.; Menezes, S.; Nunes, E. The 8th International Conference on Petroleum Phase Behavior and Fouling, Petrophase, p 109, 2007. [3] Yen, T. F.; Erdman, J, G.; Pollack, S. S. Anal Chem, 33, p 1587, 1961. [4] Andersen, S.; Jensen, J.; Speight, J. Energy & Fuels 19, p 237, 2005.

117 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

ABSTRACT 100

The Effect of Fluid Shearing and Wax Ageing on Was Deposition in Pipelines

Susana Gómez Álvarez1,2, Tony Moorwood, SPE,3 Daniel Merino García1,2, José Luis Peña Díez1,2, Xiaohong Zhang3

1Repsol, 2YPF, 3Infochem

Wax deposition in pipelines is a major concern for the oil industry. Much work has been done to model wax deposition as measured by flow loops and other experiments. Models are routinely scaled up to predict the behaviour of full-scale pipelines, but little information is available to verify if such predictions are reliable.

A wax deposition model has been adopted that combines an accurate model for the thermodynamics of wax precipitation, a model for diffusive wax deposition based on mass transfer coefficients and a term for the removal of wax by shearing caused by the turbulence of the fluid flow. The wax is treated throughout as a fully compositional distribution of n-paraffins, because previous work has shown that simplifying the representation of the n-paraffins leads to resul ts that appear to be physically unrealistic. The model has been shown to be in reasonable agreement with wax deposition rates reported from flowloop experiments.

The paper describes the application of the wax deposition model to real pipelines. The sheari ng term is more significant in larger diameter pipes, and is needed to understand their behaviour. This is illustrated by reference to the operating experience of the Rodaballo sub-sea pipeline in particular. Even though the Rodaballo pipeline is below the wax appearance temperature, it has been successfully operated for several years without active wax remediation procedures. The deposition model is analysed to assess its agreement with the Rodaballo operating experience, and to assess under what conditions the pipeline could be considered at risk of blocking.

The paper considers the effect of wax ageing on the deposit. In cases where fluid turbulence may limit wax build-up, the wax deposit may gradually harden with time due to ageing. A hardening deposit could lead to long-term remediation problems. A number of possible wax ageing mechanism are considered, and how they would modify the deposition process. It is found that the effective diffusivity of hydrocarbon molecules inside the waxy gel deposit is a major uncertainty affecting the predictions. Model sensitivities are investigated in the light of this uncertainty; the possible impact of ageing on the Rodaballo pipeline is assessed.

In conclusion, the deposition model appears to be reasonably realistic as it combines a number of potentially dominant deposition mechanisms. The study suggests that predictions of wax deposition rates may be too high if shearing is ignored which could have important implications for remediation procedures. However, the study highlights the need for more information about actual wax deposition tendencies in full-scale pipelines.

118 9th Annual International Conference on Petroleum Phase Behavior and Fouling – June 16 – 19, 2008

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