International Conference and Expo on Oil and Gas November 16-18, 2015 Dubai, UAE

Biography:

Dr. Enick has an active research area in high-pressure thermodynamics, high-pressure phase behavior and membrane separations. Most of his work, including the IAES projects, is related to CO2-rich gas mixtures. For example, Dr. Enick develops strategies for designing novel materials that have very favorable thermodynamic interactions with CO2. Previously, this research led to the identification of novel compounds, including surfactants, chelating agents and thickeners, which were extremely soluble in dense CO2. In the current work, these strategies will be used in an attempt to design high-flux, CO2-selective polymeric membranes. Polymers with specific, relatively strong thermodynamic interactions with CO2 will be cast or pressed into thin membranes. It is anticipated that these favorable interactions between CO2 and the polymer may significantly enhance the solubility of the CO2 in the membrane. Other modifications to the polymer will be incorporated to promote the diffusivity of the CO2 in the membrane. In another application, an attempt will be made to design solvents that absorb significant amounts of only CO2 at high pressure. Unlike conventional solvents that require low pressure during regeneration, all of the absorbed CO2 would be released from these novel materials with a very modest pressure drop. If successful, this solvent would be used to separate high pressure H2-CO2 mixtures into a high pressure H2 stream and a slightly lower (but still high) pressure CO2-rich stream.

Abstract:

The low viscosity of high pressure CO2 injection in oil-bearing formations leads to a host of problems, including viscous fingering, enhanced gravity override, loss of CO2 to thier zones, high produced gas-to-oil ratios, high CO2 utilization rates, and high gas re-compression costs. Water-alternating-gas (WAG) flooding remains the standard technique for reducing CO2 mobility via reduction of CO2 relative permeability, while gels can improve conformance control in stratified formations by diverting flow from thief zones. Surfactant-stabilized CO2-in-brine foams (CO2 is the high volume %, internal phase) remain a promising, low-cost means of mobility control and/or conformance control. A review of the prior use of nonionic, anionic and cationic surfactants in lab tests and pilot trials will be presented, most notably the alternate injection of aqueous surfactant solution and CO2 gas (SAG). A summary of our recent surfactant design developments will also be presented. Surfactant solubility studies, high pressure foam stability tests, static and dynamic adsorption experiments, flow-through-porous media pressure drop (i.e. mobility) results, and CT imaging of foam formation in porous media will be used to illustrate the performance of the surfactants. For example, certain amphoteric surfactants appear to be excellent foaming agents at extreme temperatures (up to ~130oC) when dissolved in high (~250000 ppm) total dissolved solids (TDS) brines, such as those found in Middle Eastern formations. With regard to nonionics, one can employ specific non-ionic surfactants that dissolve appreciably in CO2, but are even more brine-soluble. When a CO2-nonionic surfactant solution enters the formation, the surfactant will partition into the brine and stabilize the foam, thereby facilitating the continuous injection of a CO2-surfactant solution (GS process), or the alternate injection of brine and a CO2-surfactant solution (WAGS). To gain the greatest assurance that foams are generated in-situ, an operator could also inject surfactant in the brine phase and in the alternating CO2 slugs (SAGS). Finally, we will include an assessment of the CO2-soluble and brine-soluble “switchable” surfactants identified by Johnston and co-workers that exhibit a non-ionic to cationic transformation triggered by the carbonic acid that forms in the brine.

Biography:

Walaa Fathy has 18 years experience in the oil and gas industry working in different international oil companies, now he is working as a Staff Geophysicist in Petroceltic International Companies. He holds a Bachelor’s degree in Geophysics (1995) and a Master degree in Geophysics (2011) and now in progress with his PhD from Heriot Watt University in Reservoir Geophysics. He can be considered as an oil and gas finder by having several oil and gas discoveries in the Western desert and the Nile Delta in Egypt.

Abstract:

The Nile Delta is considered as the most significant gas province in Egypt and one of the most promising areas for future hydrocarbon exploration in North-Eastern Africa. The area lies to the north and south of the Nile Delta hinge zone and geologically comprises a thick sequence of tertiary aged deltaic sediments from recent to Oligocene age overlying older Mesozoic sequences. Predicting sand distribution and reservoir presence are the major exploration and development challenges associated with the complex geological settings in onshore Nile Delta. Different angle stacks have been examined to evaluate the seismic correlation with the lithology, rock properties and fluid characteristics with the emphasis on the Far and Ultra-Far low-impedance responses. The simultaneous AVO inversion has been implemented to shed light on the reservoirs complexity in which seismic reflection amplitude is inverted to P-impedance, S-impedance and density. A rock physics framework has been built for quantitative analysis where elastic properties are derived to describe the reservoir heterogeneity. We have applied the algorithm to West Dikirnis field, a strong correlation was observed between reservoir properties and both impedances as well as density. The results yielded images of reservoir elastic properties that better describe the local distribution of the sand deposits and characterize the gas sand in Qawasim formation.

Biography:

Dr. Qinglin Wu is currently Roy O. Martin Sr. Professor in Composites and Engineered Wood Products at the Louisiana State University. He received a Ph.D. in Wood Science and Engineering (Minor: Mechanical Engineering) from Oregon State University in 1993. His research emphases include wood/natural fiber polymer composites, biomaterials from natural polymers, composite durability and engineering performance, and nano-composite materials. Dr. Wu has received numerous honors and awards including 2009 LSU AgCenter Rogers Excellence in Research Award, 2008 Sigma Delta Gamma Honor Society Research Award, Fellow for International Academy of Wood Science, Markwardt Wood Engineering Award for Excellence in Wood Engineering Research and Wood Award for Excellence in Graduate Research, and Visiting Professorship from Several Universities in China. He has served on various committees and panels for professional societies and government agencies. Dr. Wu’s research is published in over 100 technical papers in journals, books, and proceedings. His research has been supported by the National Science Foundation (NSF), Louisiana Board of Regents, USDA National Research Initiative Competitive Grants Program (NRICGP), USDA/DOE Biomass Research Program, and wood-products industry. Dr. Wu teaches both undergraduate and graduate courses in the School of Renewable Natural Resources. These courses include Wood Science and Forest Products, Wood Composite Manufacturing, and Wood/Wood Composite Mechanics.

Abstract:

Rheological and filtration characteristics of drilling fluids are considered as two critical aspects to ensure the success of a drilling operation. This research demonstrates the effectiveness of cellulose nanoparticles (CNPs), including microfibrillated cellulose (MFC) and cellulose nanocrystals (CNCs) in enhancing the rheological and filtration performances of bentonite (BT) water-based drilling fluids (WDFs). CNCs were isolated from MFC through sulfuric acid hydrolysis. In comparison with MFC, the resultant CNCs had much smaller dimensions, more negative surface charge, higher stability in aqueous solutions, lower viscosity, and less evident shear thinning behavior. These differences resulted in the distinctive microstructures between MFC/BT and CNC/BT-WDFs. A typical “core-shell” structure was created in CNC/BT-WDFs due to the strong surface interactions among BT layers, CNCs and immobilized water molecules. However, a similar structure wasn’t formed in MFC/BT-WDFs. As a result, CNC/BT-WDFs had superior rheological properties, higher temperature stability, less fluid loss volume, and thinner filter cakes than BT and MFC/BT-WDFs. Moreover, the presence of polyanionic cellulose (PAC) further improved the rheological and filtration performances of CNC/BT-WDFs, suggesting a synergistic effect between PAC and CNCs.

Biography:

Dr. Teng Lu received a Ph.D. in oil-gas field development engineering from China University of Petroleum in 2014. His research emphases include enhanced heavy oil recovery, CO2 EOR and sequestration and foam flooding.

Abstract:

Heavy oil is an important part of the world’s energy supply and is increasingly being exploited as the demand for petroleum increases. There are abundant ultra-heavy oil resources in China. This paper briefly introduces two enhanced ultra-heavy oil recovery techniques in China including CO2 and dissolver assisted steam huff and puff technology for horizontal wells (HDCS) and Gas-SAGD (Adding N2 in the process of SAGD). The HDCS technique is developed to the ultra-heavy oil reservoirs in the Shengli Oilfield because of high oil viscosity, deep and thin layer, high rate of resin and asphaltene. The HDCS combines the techniques of efficient oil-soluble dissolver, CO2 immiscible and steam huff and puff which can effectively reduce the steam injection pressure, expand the steam swept area and improve oil production rate. Field tests show that HDCS is good at reducing viscosity and improving production of super-heavy oil reservoirs. The Gas-SAGD is developed to the Guantao reservoir of Du 84 block in Liaohe oilfield. The oil layer of Guantao reservoir has a direct contact with the top water. As the steam chamber rises in vertical direction, the heat of steam will soften bitumen shell under top water. The Gas-SAGD can improve the condition of steam chamber and prolong the life time of SAGD. As of June 2011, the Gas-SAGD has been applied in three regions which include seven slugs. Field tests show that it is effective in reducing steam 1.391×105 t, increasing oil production 2.07×104 t and improving steam oil ratio 33.3%.

Biography:

Yue Ping has completed his PhD at the age of 30 years from Southwest Petroleum University. He is the associate professor of SWPU. He engages in oil and gas reservoir development theory, method and technology research. His research interests include horizontal and multi-branched well well-bore flow and reservoir seepage coupled model.

Abstract:

It is well-known that barriers have a significant impact on the production performance of horizontal wells developed in a bottom water drive reservoir. Since MUSKAT and WYCKOFF introduced the water coning phenomenon and theory to petroleum engineering, horizontal well’s critical rate calculations, water breakthrough time predictions and water cut reductions have been investigated. The methods reported in literature for controlling water cut include perforating far away from the original water-oil contact (WOC), producing oil below the critical rate, producing oil and water separately with downhole water sink (DWS) or downhole water loop (DWL) technology, and injecting polymers to form a barrier. Barrier impacts on water cut and critical rate of horizontal well in bottom water reservoir have been recognized but not investigated quantitatively. Considering the existence of barriers in formations, this presentation will intuduce our research about horizontal well flow model with barriers when the water cresting forms in bottom water reservoir. The research result shows that barrier increases critical rate and delays water breakthrough. Further study the barrier size, location and permeability shows that the increases of barrier size and barrier height led to the higher critical rate. But the incremental rate more and more litter. For a given barrier size and position, the critical rate and critical potential difference monotonically decrease as the barrier permeability increases. The case study shows the method presented here can be used to predict the critical rate in the bottom water reservoir and applied to investigate the horizontal well behavior of water cresting.

Biography:

Abstract:

In recent years, the largest integral single gas field of the lower Cambrian Longwangmiao formation with proved reserves of 4403×108 m3 was found in Sichuan basin, China and the main production is from Longwangmiao formation grain dolomite. Based on observation of outcrops, cores and thin sections and analysis of logging data and experiment, the features, main controlling factors, evolution and distribution of the Longwangmiao formation reservoirs in the lower Cambrian, Sichuan basin are examined carefully and the distribution of favorable reservoirs is predicted. The Longwangmiao formation reservoirs are grain shoal-dolostone fracture–vug type made up of residual dolarenite, oolitic dolomite and crystal dolomite with vugs and dissolution pores as the main storage space, residual inter-granular pores, inter-crystalline pores and fractures as the secondary storage space, these reservoirs have a porosity of 2% to ~8%, 4.28% on average and a thickness of 20m to ~60 m, 36 m on average. Shoal facies and penecontemporaneous dissolution are the main factors controlling the reservoir occurrence. Grain shoal, the basis of reservoir development controls the phases and distribution of reservoir. Penecontemporaneous dissolution is the key factor affecting the formation of the main reservoir space. In addition, penecontemporaneous dolomitization plays a constructive role in the preservation of the pores formed earlier and generation of micro-fractures in late stage. The reservoirs experienced four evolution stages. The sedimentation and penecontemporaneous dissolution in pore-forming period laid the material basis for reservoir space types and physical property conditions. Supergene karstification and burial dissolution made some contributions to the improvement of reservoir physical properties. Hydrothermal mineral filling and asphalt filling are the main factors making reservoir quality worse. Based on the main controlling factors of the Longwangmiao reservoir, the favorable reservoir zones are ancient high topography areas between Huayingshan Fault and Longquanshan Fault and breakthroughs are expected to make in the Guangan-Nanchong-Jiange area.

Biography:

Saber Mohammadi is currently research assistant at Research Institute of Petroleum Industry (RIPI), Tehran, Iran. He is also completing his PhD in petroleum engineering at Amirkabir University of Technology, Tehran, Iran. He holds MSc degree from Sharif University of Technology, Tehran, Iran, and BSc degree from Petroleum University of Technology, Ahwaz, Iran (all in reservoir engineering). His academic experience includes research on experimental-simulation studies of different EOR processes in heavy oil reservoirs, micro-scale transport phenomena, micro-model experiments, and application of nanoparticles in heavy oil recovery. He has authored/co-authored more than 40 technical papers which have been presented and/or published in international conferences and journals.

Abstract:

Understanding the porous media wettability is crucial for optimizing EOR processes. The oil-water wetting preferences strongly affect all facets of reservoir performance, mainly in waterflooding process as an EOR technique. The use of nanotechnology has recently gained momentum in oil and gas industry. However, the role of nanoparticles on wettability conditions of porous media has remained a topic of debate in the available literature. In this work, the effect of hydrophilic silica nanoparticles on wettability of reservoir rock is investigated through contact angle measurement of oil-water-rock system, and pore-scale water flooding in five-spot glass micro-models at different temperatures and concentration of nanoparticles. Obtained results showed that the wettability of oil-wetted rocks in presence of silica nanoparticles changes from oil-wet to water wet. Furthermore, as the temperature of the system and concentration of nanoparticles increase the effect of nanoparticles on wettability alteration of reservoir rock is much more pronounced. Also, the wettability alteration occurred in less time in this situation. The results of flooding experiments with nanosolution illustrated that the oil recovery factor and breakthrough time of displacing fluid increases in presence of nanoparticles dispersed in water upto concentration of 0.50 wt%; for concentration of nanoparticles more than 0.50 wt%, the recovery factor decreased due to reduction of porous medium permeability as well as plugging of pores-throats by dispersed nanoparticles. Results of this work reveal the potential applications of silica nanoparticles on wettability alteration of porous media as well as on improvement of oil recovery efficiency during water flooding process.

Biography:

Fatma Taktak, PhD in Geological Sciences - Faculty of Sciences, Sfax University – Tunisia. 13 years experience in the oil and gas Exploration and Expert in the analysis of well logging data and developing new well logging techniques, wellbore stability while drilling and basins modelling using 2D seismic technics in different oil companies in Tunisia,. Have some research paper in ISI well known geological journal. Now She is working as a Assistant Professor at University of Modern Sciences UMS, College of Business, Dubai, United Arab Emirates and responsible for the Maters of Science Program in Petroleum Operations Management.

Abstract:

Because of the complexity of the pore network and the high heterogeneity of Ashtart carbonate reservoir in the Gulf of Gabes a study was required for a precise knowledge of the main reservoir parameters including porosity, permeability and irreducible water saturation. The main objective is to present a global petrophysic architecture model of the El Garia Formation reservoir for the Gulf of Gabes basin - GGB - during the Eocene period, using a detailed interpretation of a the petrofacies texture, geometry and petrophysical parameters of which were apprehended using seismic profiles; gamma-ray and sonic lateral logs, as well as cores and cuttings taken in drill wells. Estimation of the initial water saturation and hence variations in the capillary pressure in the reservoir, required compilations of porosity data measured on cores, supplemented by additional but computed porosities based on acoustic log diagrams. Furthermore, Gamma Ray, Sonic log, and well to well correlations tied to core results and well cuttings, help recognize the layered lithologies within the El Garia flat lying but stratified, Ypresian in origin reservoir rocks. Abundant permeability and porosity values compiled in the light of seismic sequence and Gamma Ray and Sonic log details, were integrated in an empirical approach using the Leverett J function, to model the irreducible water saturation depending on the capillary pressure distribution in the whole reservoir. We suggests that diagenesis prevalently controls porosity, due to operative dissolutions of the Nummulitid tests/bioclasts, and cementation; moreover, diagenesis exerts effects on permeability by interconnecting intergranular and intratest pore spaces. In contrast, microfracturing enhances permeability of the reservoir. This is notably the case in the fairly permeable central zone in the Ashtart reservoir with excellent petrophysical parameters, but which were found to degrade gradually towards its peripheries.

Biography:

Shabnam Shahbazi is a PhD Student of Petroleum Reservoir Engineering in Amirkabir University of Technology (Tehran Polytechnic). She works as a Teacher in Petroleum Department of Science and Research Branch, Islamic Azad University. She also has been working in Pars Oil and Gas Company from 2006. She is the Head of Upstream Section of POGC Phase-12 Project; this section is responsible for all upstream issues (geology, reservoir and drilling) regarding Phase-12 Project.

Abstract:

Transient pressure test of horizontal wells compared to vertical wells is more complicated due to the occurrence potential of different transient flow periods. Although various mathematical models were developed to horizontal well test analysis their evaluation in different well and reservoir conditions needs more investigation. In specific, in vertical wells non-Darcy flow which causes an extra pressure drop have a significant impact on well test data but its impact on horizontal well test data needs more investigation. The objective of this paper is to examine transient pressure behavior of horizontal gas wells under various conditions including high velocity flow. The results show that the appearance of elliptical and pseudo-radial flow regimes depends on relative well length and formation thickness. In addition, the effect of off-centered wells respect to upper and lower boundaries in transient pressure data is expressed. The results also show that non-Darcy flow can cause a significant skin in transient data of a horizontal gas well. Magnitude of the skin is mainly affected by reservoir permeability and production rate of the horizontal well.

Biography:

Arian Velayati is a young researcher and engineer born in July 03, 1990. Velayati is a researcher of drilling fluids at Research Institute of Petroleum Industry in Tehran. He earned a BS degree from science and research university of Tehran and MS degree from Shahrood university of tech, both in petroleum engineering and as the top student. He was acknowledged as “Scientific elite” by the national elites foundation of Iran in the year 2014 as a result of his publications, GPA and researches. Velayati is also a lecturer and developer of drilling engineering softwares.

Abstract:

Gas migration through cement slurry is a worldwide challenge. Gas invasion could lead to financial damages and fatal incidents. Major oil companies devised specially designed approaches to face the problem of gas migration, many additives have been introduced and several techniques have been utilized. We have reported on the effect of thixotropic agents on reducing transition time, critical hydration time, modification of the gel strength profile and generally prevention of gas migration through cement slurries. The research was conducted based on a detailed checklist for cement slurry design optimization. Resulted paper was published in journal of natural gas science and engineering (Elsevier). The results of the research indicate advantages of thixotropic agent utilization in cement slurry composition and facing the problem of gas migration. As the final stage of the slurry optimization plan the results were verified using fluid migration analysis (FMA) test. According to the results, total gas migration flow rate of cement slurry optimized using the presented checklist was recorded as 0.23 ml/min. It was also observed that thixotropic agents improved gel strength profile, filtration control, waiting on cement time (WOC) , critical hydration time and cement transition time significantly.

Biography:

Dr. Nasvi received his BSc (Eng) degree (First Class Honours and University prizes) from University of Peradeniya, Srilanka in 2009 and after that he worked as a temporary lecturer in the same university for a period of one year. He obtained his PhD degree in Geotechnical Engineering from Monash University, Australia in 2013. His PhD thesis title was “Geopolymer as well cement for geological sequestration of carbon dioxide”. At present, he is working as a senior lecturer at department of Civil Engineering, University of Peradeniya, Srilanka. He has published many journals and conferences in the areas of carbon capture storage, oil adn gas and energy fields.

Abstract:

Carbon capture and storage (CCS) is found as a viable method for long-term reduction of greenhouse gases. In a CCS project, mechanical integrity of well cement should be maintained to sustain the required mechanical strength throughout the life of an oil/gas and CO2 sequestration well. One of the major issues with existing OPC based oil well cement is cement degradation in CO2-rich environments. On the other hand, researchers have found that geopolymer cement possesses excellent acidresistant characteristics, shows higher mechanical strength and durability and demonstrates lower permeability. Therefore, this research work focused on studying the mechanical integrity of geopolymers under two different conditions: (1) effect of CO2 on mechanical behaviour of geopolymers and (2) hydraulic fracturing of geopolymers to study the mechanical integrity under down-hole stress conditions. To study the emchanical integrity under CO2 rich environment, fly ash-based geopolymers were tested in CO2 chamber at apressure of 3 MPa for up to 6 months and uniaxial compressive strength testing was conducted to study the mechanical behaviour of geopolymer in CO2. It was noted that there are no significance changes in compressive strength and Young’s modulus of geopolymer in CO2 after 6 months. The variations in compressive strength values in CO2 were within 2% compared to the compressive strength value prior to CO2 exposure. Scanning electron microscopy (SEM) testing was conducted to study any microstructural changes in CO2, and the SEM results revealed no significance variation in the microstructure of geopolymer after 6 months of CO2 exposure.For hydraulic fracturing experiment, four different tests were conducted by changing the injection pressure (Pin), axial stress (σ1), confining pressure (σ3) and tube length (30 mm and 40 mm). Geopolymers could not be fractured in any of the tests, which employed maximum values of Pin and σ1 as 23 MPa and 59 MPa respectively. Even though maximum ratios of Pin/ σ3 of 3.8 and σ1/ σ3 13.3 were used, fracture development was not observed. The results of this experiment lead to the conclusion that geopolymers can provide the required mechanical integrity in CO2 injection wells, as the absence of fractures in geopolymer under extreme stress conditions eliminates one of the possible CO2 leakage pathways.

Biography:

Sushanta K. Mitra, PhD, PEng is Professor & Chair of Mechanical Engineering Kaneff Professor in Micro & Nanotechnology for Social Innovation Fellow CSME, ASME, EIC, RSC, CAE Fellow, National Institute for Nanotechnology (NRC, Canada) Lassonde School of Engineering York University, Toronto

Abstract:

Biography:

Abstract:

Long-stroke sucker-rod pumping units have polished rod stroke lengths greater than 24 ft and require significantly less torque than beam pumping units. To produce high liquid volumes they can be run at much lower speeds and can thus achieve greater overall system efficiencies. The general advantages of long-stroke pumping over traditional pumping can be summed as: (a) greater liquid producing capacities are achieved, (b) downhole pump problems are decreased, and (c) rod string life is substantially increased due to the reduced number of stress reversals. This paper presents a complete coverage of present-day long-stroke rod pumping methods and discusses the two main types of technologies available: Rotaflex and DynaPump. After a short historical overview of long-stroke pumping these two units are introduced and their technical and operational features are described in detail. The relative advantages and limitations of Rotaflex and DynaPump installations are summarized to facilitate their selection for artificial lift applications.

Biography:

Abstract:

High water production is a major issue for upstream oil and gas operators due to massive water injection. Reducing the water production while improving oil recovery from these fields is a key challenge. Polymer based gels have been widely used to improve reservoir conformance problems and to reduce excess water production. Unfortunately, polymer gels are not suitable for high temperature reservoirs (> 100 °C), because at high temperature polymer gels loss both stability and effectiveness. The present study reports on laboratories experiments carried out to investigate rheological properties and propagation of modified bentonite clay particles in a heterogeneous sand pack. A series of sand pack flooding tests were conducted on modified bentonite clay diluted in brines of various salinities, pH, and various particles concentrations. Propagation, retention and dispersion of modified bentonite were studied in a heterogeneous sand pack represented by three parallel cylindrical cores flow model with different permeability. These tests evaluate injectivity and determine permeability reduction. Results showed that a high flow resistance developed across the sand pack demonstrating high retention and adsorption of modified bentonite in the sand pack. Results also suggested another very significant advantages that modified bentonite could be selectively injected into high permeability zones due to low viscosity of particles dispersion. These positive results bring new promising insights for successful applications of modified bentonite.

Biography:

Abstract:

Ras Fanar oil field is located in the western offshore concession area of Gulf of Suez, some 3 km.east Ras Gharib field in a water depth of about 100 ft. The main reservoir in Ras Fanar Field is the Middle Miocene reefal limestone (Belayim Nullipore). Middle Miocene Shallower Horizons Zeit Formation have locally proved potential in Ras Fanar oilfield, good represented by Zeit Sand Member (basal part of Zeit Formation) as secondary target. Zeit Sand secondary reservoir about 17 ft. average thickness, porosity ranging from 18-35 and average water saturation 15%. KK84-3 old Exploratory well Penetrated 15 ft. thick of Zeit sand and tested 350 BOPD from 10 ft. net Pay thickness , API 28.4 , reservoir driving by solution gas driving mechanism. Mud Gas Data analysis integrated with available logs and oil shows gives good indication to extension and reservoir characterization of Zeit sand. This paper show how you can detect low pay zone thickness while drilling by using Mud gas data analysis by multiple methods graphical and mathematical, it’s give excellent indication to select the interesting interval to run logs or well test and how can we improve reserve by integration between geological data and reservoir engineering data.

Biography:

Dr. Waleed AlAmeri received his B.S. degree in Petroleum Engineering from the Louisiana State University and A&M College, Baton Rouge, LA, USA, in 2006. Dr. Waleed AlAmeri pursed his graduate studies at Colorado School of Mines, Golden, CO, USA, and received his M.S. and PhD. degrees in Petroleum Engineering in 2010 and 2015, respectively. He joined the Petroleum Institute in Abu Dhabi (Department of Petroleum Engineering) on May 2015 as an assistant professor. The topic of his PhD was on “Low Salinity Waterflooding in a Low Permeability Carbonate Formation of a Giant Middle East Field”.

Abstract:

Low-salinity water injected into carbonate cores, which have undergone sea-water injection, can produce additional oil more economically if a low-concentration non-ionic surfactant is added to the low-salinity water and injected as chase fluid. One major reason for the additional oil recovery is that low-concentration surfactant effectiveness favors the low-salinity environment. Several coreflooding, contact angle, and IFT experiments were performed to assess the proposed process. The core flooding sequence includes seawater, low-salinity water, and low-concentration non-ionic surfactant. However, for field application, we proposed low-salinity water-alternate-surfactant injection. The surfactant concentration in low-salinity water was 1,000 and 5,000 ppm. The core permeability is 0.5 to 1.5 md, and porosity ranges from 0.18 to 0.25. Cores were aged for eight weeks at reservoir pressure and temperature. The pendant drop oil-brine IFT and captive oil-droplet contact angle measurements were performed at variable brine salinity in the presence of surfactant. Seawater and low-salinity waterflooding corefloods yielded ultimate oil recoveries of up to 57 percent. Up to 6 percent additional oil recoveries was obtained from low-concentration non-ionic surfactant in low-salinity waterflood. With decreasing salinity, in presence of 1,000-ppm surfactant, favorable wettability alteration from intermediate-wet to water-wet was observed by contact angle measurements. Moreover, addition of small concentration of surfactant decreased the IFT and altered the wettability of several one-inch diameter, crude-aged, discs to water wet.

Biography:

Professor Khalil Sarkarinejad is micro-structural and structural geologist graduated at Cardiff University in Wales, head of Structural Geology Group at the Department of Earth Sciences, Shiraz University with extensive publications and reseach in the hinterland, foreland of the Zagros orogenic belt, controlling factors in the inclined curved transpression deformations.

Abstract:

The Abadan plain in southwestern Iran has important petroleum reservoir potential in the Zagros Fordland Folded Belt parallel to the Foreland Fold-and-Thrust Belt of the Zagros orogenic belt. This reservoir despite its gentle anticline is much more complex and poorly defined by its structural setting. It is located at the Mesopotamian fore deep basin, bounded by the marginal part of the Zagros Foreland and the Dezful Embayment inverted graben. The main reservoir in this field is the Fahliyan formation, composed of reef carbonates. Most of the Abadan area is flat and covered by recent alluvial deposits with no outcrops. Studies of the structures in this area have provided information about the structural history and allowed better reservoir and drilling management. For better understanding structure and complexity of this reservoir, seismic spectral decomposition techniques have been utilized as a quick and effective interpretation tool. Fast Fourier transform (FFT) and continuous wavelet transforms (CWT) have been used to convert time to frequency domain, and have been applied to detect fault systems in the reservoir. Application of the Fast Fourier transform (FFT) and continuous wavelet transforms (CWT) indicate that the Abadan reservoir consists inverted thrust system of the reservoir which display an early extensional system and have been inverted to dip-slip thrusting paralleling of contour common depth in two sides of the system in some regions and large displacement between two sides of contours in which hanging wall moved over footwall. Various displacements between sides indicate parallel inverted movements which are associated with later compressional faulting and displacement which indicate inversion tectonics.

Biography:

Mehdi Reza Poursoltani graduated from University of Mashhad, Iran. He obtained his M.Sc. and Ph.D. degrees from the Islamic Azad University of Tehran, Iran, and his doctoral thesis was a study of Jurassic depositional environments and petrography, carried out with Dalhousie University in Canada. Much of his subsequent work has been on sedimentary environments and petrography, particularly of formations in Iran. His current interests include assessment of environments, provenance and diagenesis of Cambrian and Devonian rocks in Iran, in part during a sabbatical year at Dalhousie University.

Abstract:

Across a large area of Central Iran, the Lalun Formation rests on older sedimentary rocks. Based on our study, three fluvial to shallow-marine facies associations of shale-sandstone and conglomerate are present. Elsewhere in the Middle East and North Africa, equivalent Cambrian clastic deposits contain hydrocarbon reservoirs, and this study presents the first analysis of porosity in strata of this age in Iran. The sandstones range from quartzarenite to arkose, feldspathic litharenite and rarely litharenite. Diagenetic events included compaction and pressure solution, cementation, grain fracturing, alteration, dissolution and replacement. Dissolution is prominent in the sandstones. The sandstones show variable degrees of compaction. Based on petrological and geochemical studies, we infer early, deep burial and late stages of diagenesis. A few porosity estimates from thin sections were high, and inspection shows that these more porous samples are either highly fractured or are unusually rich in partially dissolved feldspar. The bulk of the porosity appears to be secondary. Intragranular pores are prominent in feldspathic litharenites, especially as large spaces along cleavage planes and fractures. Intergranular pores are present locally where carbonate cements have been corroded; parts of these pores could be primary. Additional intercrystalline micropores are present between authigenic clay minerals and calcite and dolomite crystals. Microfractures are prominent within many grains. Those in quartz grains generally have been healed with silica, although some are filled with carbonate and iron oxides. Fractures form much of the porosity in some samples, and our assessment of porosity percent and type for these surface samples.

Biography:

Abdollah Esmaeili got his Diploma in Mathematics & Physics, 1986 - 1990, Iran. He attained his BSc and MSc in petroleum engineering from Petroleum University of Technology (PUT), Iran. He is currently pursuing his PhD degree in petroleum engineering at University Technology Petronas (UTP), Malaysia. He has been working as a reservoir engineer in the oil & gas industry for the past 25 years for companies like National Iranian Oil Company (N.I.O.C), National Iranian South Oil Company (N.I.S.O.C), Aghajari Oil & Gas Production Company (AjOGPC). Also, he teaches petroleum reservoir engineering courses in Universities of Iran and Worldwide. He has written several papers in petroleum engineering accepted for presentation in international conferences. He has attended to several international conferences worldwide as speaker. He has lead several international scientific master class and workshops Worldwide.

Abstract:

In formations where the sand is porous, permeable and well cemented together, large volumes of hydrocarbons which can flow easily through the sand and into production wells are produced through perforations into the well. These produced fluids may carry entrained there in sand, particularly when the subsurface formation is an unconsolidated formation. Produced sand is undesirable for many reasons. When it reaches the surface, sand can damage equipment such as valves, pipelines, pumps and separators and must be removed from the produced fluids at the surface. Further, the produced sand may partially or completely clog the well, substantially lead to poor performance in wells and, ultimately, inhibiting production, thereby making necessary an expensive work-over. In addition, the sand flowing from the subsurface formation may leave therein a cavity which may result in caving of the formation and collapse of the casing. Sand production in oil and gas wells can occur if fluid flow exceeds a certain threshold governed by factors such as consistency of the reservoir rock, stress state and the type of completion used around the well. The amount of solids can be less than a few grams per cubic meter of reservoir fluid, posing only minor problems, or a substantial amount over a short period of time, resulting in erosion and in some cases filling and blocking of the wellbore. Although major improvements have been achieved in the past decade, sanding tools are still unable to predict the sand mass and the rate of sanding for all field problems in a reliable form. This paper provides a review of selected approaches and methods that have been developed for sanding prediction. Most of these methods are based on the continuum assumption, while a few have recently been developed based on discrete element model. Some methods are only capable of assessing the conditions that lead to the onset of sanding, while others are capable of making volumetric predictions. Some methods use analytical formulae, particularly those for estimating the onset of sanding while others use numerical methods, particularly in calculating sanding rate.

Biography:

Dr. Nabil M. Al-Areeq is Associate Prof. of Petroleum Geology and Sedimentalogy Vice Dean for Academic Affairs, Department of Geology and Environment Faculty of Applied Science Thamar University, Thamar-Yemen

Abstract:

The objective of this study is to provide information on source organic matter input, depositional conditions and the correlation between crude oils recovered from Sunah oilfield and Upper Jurassic Madbi Formation. A suite of twenty-six crude oils from the Lower Cretaceous reservoirs (Qishnclastic) of the Masila Region (Eastern Yemen) were analyzed and geochemically compared with extracts from source rock of the Upper Jurassic (Madbi Formation). The investigated biomarkers indicated that the Sunah oils were derived from mixed marine and terrigenous organic matter and deposited under suboxic conditions. This has been achieved from normal alkane and acyclic isoprenoids distributions, terpane and sterane biomarkers. These oils were also generated from source rock with a wide range of thermal maturity and ranging from early-matureto peak oil window. Based on molecular indicators of organic source input and depositional environment diagnostic biomarkers, one petroleum system operates in the Masila Region; this derived from Upper Jurassic Madbi organic-rich shales as source rock. Therefore, the hydrocarbon exploration processes should be focused on the known location of the Upper Jurassic Madbi strata for predicting the source kitchen.

Biography:

Abstract:

Condensate drop out and accumulation along with high water saturation near the wellbore region result in a decrease in the gas relative permeability. The main objective of this study is to evaluate the feasibility of increasing the relative permeability to gas in limestone cores via use of methanol to either eliminate or minimize the impact of condensate accumulation. In this research, the effect of methanol treatment on condensate-blocked rocks was simulated using the Cubic-Plus-Association (CPA) equation of state. The CPA equation of state was applied to the modeling of two-phase flows through cores for methanol hydrocarbon mixtures due to charge transfer and hydrogen bonding, both of which may strongly affect the thermodynamic properties of such mixtures. Differential equations were solved by means of the orthogonal collocation method, a method particularly attractive for solving nonlinear problems. Core flooding experiments were performed on low-temperature fractured carbonate cores; chosen from one of Iranian carbonate gas. Experimental tests were conducted in 1.5 inch Diameter carbonate cores, using reservoir fluid and synthetic/field brine. Moreover, the results show that methanol treatment can improve gas relative permeability varies from a factor of 1.12 to 1.64. A good agreement was achieved between the experimental results and modeling in the prediction of gas relative permeability before and after methanol treatment when the flowing bottom-hole pressure falls below dew point pressure. These results may help reservoir engineers and specialists to restore the lost productivity of gas condensate.

Biography:

Abstract:

With more than 1500 Tcf of gas reserves discovered in more than 25 fields, Gavbandi province of the Zagros, contains about 15% of the world’s proven gas reserves; discovered in fractured Permo-Triassic carbonates, sealed by the thick Triassic evaporates and originated from Lower Silurian highly organic shales. Anticlines located in the region are potentially prospective regarding burial and migration history, as well as the source, reservoir, and cap rock characteristics; and they are suggested for drilling if structural conditions are provided. Subsurface data sets acquired during the recent and successful hydrocarbon exploration in the Gavbandi area showed that the Triassic Dashtak evaporites form an efficient tectonic detachment horizon, decoupling the post-Triassic succession from the Permo–Triassic rocks as reservoirs for gas. The variations of fold geometry and fold crest location across the detachment horizon complicated the selection of the targets for gas at depth. Exploration wells drilled on the crest of several anticlines in the region indicated the rapid thickness variation of the Dashtak evaporites from one anticline to the next. The main objectives of this study are to Impact of Abnormal Fluid pressure within an Evaporitic Cap Rock on the Planning of Gas Exploration Wells in Zagros. To achieve these objectives, a synthesis of well logs, drilling mud weight data as well as depth-converted seismic profiles were analyzed to figure out anomalous high fluid pressure within the Triassic evaporitic cap rock (the Dashtak Formation) and its impact on the geometry of anticlinal traps in the gas rich Gavbandi area located in the south eastern part of the Zagros. The results indicated that the location of anticlinal traps at the depth of Permo-Triassic reservoir is horizontally shifted with respect to surface crest of many anticlines within the Gavbandi area. This Crestal shift across the Dashtak Formation may induced by abnormally high fluid pressure in the ‘A evaporite’ member of the Dashtak Formation, detected in many exploration wells across the area. When fluid pressure increases due to compaction during folding, the higher shaliness could probably cap more fluids and consequently increase the fluid pressure within the Dashtak Formation. Anomalous high fluid pressure decreases internal friction and shear strength of rock units and facilitates fracturing and faulting within the Dashtak Formation and consequently cause crestal shift of anticlinal traps. This should be taken in consideration when planning a new exploration well in Gavbandi area, in order to prevent out of trap drilling.

Biography:

Shahenaz A. Vahora, age 27 years, born on 6th June 1987 in Vadodara, Gujarat. She received her Bachelor’s in Science with Physics as Major and Mathematics and Chemistry as subsidiary subjects in the year 2009 and Master in Applied Physics in the year 2011 from from Maharaja Sayajirao University, Vadodara, Gujarat. I have done my project on Nano Technology – study with the aim to increase efficiency of solar cell by doping of magnesium in zirconium. She has also Air – Wing NCC-I training during her Bachelor’s Programme. In August 2011 she joined and currently associated with Parul Institute of Engineering and Technology (Diploma Studies) as a Lecturer in Physics.

Abstract:

Petro physics is the study of physical and chemical rock properties and their interactions with fluids. The most petro physicists work in the hydrocarbon industry, some also work in the mining and water resource industries. The properties measured or computed fall into three broad categories: conventional petro physical properties, rock mechanical properties, and ore quality. Some of the key properties studied in petro physics are(1) litho logy, (2)porosity, (3)water saturation,(4) permeability and(5) density. A key aspect of petro physics is measuring and evaluating these rock properties by acquiring well log measurements - in which a string of measurement tools are inserted in the borehole, core measurements - in which rock samples are retrieved from subsurface, and seismic measurements. These studies are then combined with geological and geophysical studies and reservoir engineering to give a complete picture of the reservoir. Properties of petro physics: (1)Litho logy: A description of the rock's physical characteristics, such as grain size, composition and texture. By studying the litho logy of local geological outcrops and core samples, geoscientists can use a combination of log measurements, such as natural gamma, neutron, density and resistivity, to determine the litho logy down the well. (2)Porosity: The percentage of a given volume of rock that is pore space and can therefore contain fluids. This is typically calculated using data from an instrument that measures the reaction of the rock to bombardment by neutrons or by gamma rays but can also be derived from sonic and NMR logging. (3)Water saturation: The fraction of the pore space occupied by water. This is typically calculated using data from an instrument that measures the resistivity of the rock and is known by the symbol . (4)Permeability: The quantity of fluid (usually hydrocarbon) that can flow through a rock as a function of time and pressure, related to how interconnected the pores are. Formation testing is so far the only tool that can directly measure a rock formation's permeability down a well.[citation needed] In case of its absence, which is common in most cases, an estimate for permeability can be derived from empirical relationships with other measurements such as porosity, NMR and sonic logging. (5) Density: Density is a function of composition, porosity and saturation .Density is calculated from mass and volume measurements. Mass is determined by carefully weighing the sample on an analytical balance. For irregular shaped samples, volume is usually based on Archimedes’s principle. The stereo pycnometer determines volume based on the displacement of gas. Application of petro physics: (1)The determination of litho logy, net pay, porosity, water saturation, and permeability from wellbore core and log data. The chapter deals with "Development Petro physics" and emphasizes the integration of core data with log data; the adjustment of core data, when required, to reservoir conditions; and the calibration and regression line-fitting of log data to core data. The goal of the calculations is to use all available data, calibrated to the best standard, to arrive at the most accurate quantitative values of the petro physical parameters (i.e., lithology, net pay, porosity, water saturation, and permeability). Log analysis, cased-hole formation evaluation, and production logging are not covered here. (2) Petro physical data sources and databases, litho logy determination, net-pay determination, porosity determination, fluid-contacts identification, water-saturation determination, permeability calculations, case studies, other considerations in petro physical calculations, and summary and conclusions. It does not cover the propagation of the wellbore values, or "populating" of static or dynamic reservoir models, vertically and a really over the whole of the reservoir volume.

Biography:

Abstract:

It is well known that NMR is already used in various core laboratory analyses to characterize rock and fluids, obtain pore-size distribution, determine porosity and even evaluate rock wettability qualitatively using different numerical methods. The development of A SINGLE ANALYTICAL expression relating the porosity, permeability, diffusion coefficient, NMR/MRI relaxation parameters and the transverse magnetization will significantly enhance the present understanding of these petro physical properties. Our goal is to apply a generally applicable and simple approach which may yield useful information from NMR signals of different petro-physical properties useful in Petroleum and Gas industry. This presentation is based on a model of the Bloch NMR diffusion equation for complex pore geometries in which the transverse magnetization is obtained as a function of reservoir chemical (relaxation) and physical properties. The NMR signal is also shown to be dependent on the tortuosity and relaxation rate of rocks fluid so that reservoirs comprised of mixed lithology and mineralogy can be easily evaluated. The novel model may open up new research opportunities which can be jointly explored with any Oil and gas Company. For example, it can be used to visualize and track the saturation front during displacement experiments (dynamic measurements). The difficulty in estimating permeability from grain-size distributions or from well logs can be reduced very significantly if the simple analytical expression obtained from the Bloch NMR flow equation as a function of permeability, porosity, tortuosity and diffusion coefficient is fully explored.

Biography:

Abdollah Esmaeili got his Diploma in Mathematics & Physics, 1986 - 1990, Iran. He attained his BSc and MSc in petroleum engineering from Petroleum University of Technology (PUT), Iran. He is currently pursuing his PhD degree in petroleum engineering at University Technology Petronas (UTP), Malaysia. He has been working as a reservoir engineer in the oil & gas industry for the past 25 years for companies like National Iranian Oil Company (N.I.O.C), National Iranian South Oil Company (N.I.S.O.C), Aghajari Oil & Gas Production Company (AjOGPC). Also, he teaches petroleum reservoir engineering courses in Universities of Iran and Worldwide. He has written several papers in petroleum engineering accepted for presentation in international conferences. He has attended to several international conferences worldwide as speaker. He has lead several international scientific master class and workshops Worldwide.

Abstract:

Among existence methods for produced water removal from oil reservoirs, water re – injection into underground layers of reservoir has been considered as suitable method. But solid particles and other pollutants in this water will damage reservoir formations. Scale deposition is one of the most serious oil field problems that inflict water injection systems primarily when two incompatible waters are involved. Formation damage in this process is similar to cross flow filtration. In this paper, external cake formation on well bore has been modeled in unsteady state conditions. For this purpose, first, the forces will be analyzed; then, fluid force and mass balances in unsteady state condition will be written. Finally, cake thickness, invasion and well fluid velocity profiles in unsteady state condition will be obtained.

Biography:

Abstract:

A new logging-while-drilling (LWD) technology has been developed and field-tested, which introduces directional electromagnetic (EM) measurements through the use of tilted and transverse current-loop antennas. The multispacing and multifrequency directional measurements enable monitoring distance to formation boundaries and their orientation to facilitate proactive well placement. In combination with conventional LWD resistivity, these directional EM measurements allow for accurate structure and formation resistivity interpretation around the wellbore, independent of mud type. Furthermore, specific antenna combinations provide the capability to detect and characterize resistivity anisotropy in near-vertical wells while drilling. The directional EM tool is designed with a symmetrical transmitter-receiver configuration that optimizes the sensitivity to the desired formation parameters. While canceling the influence of anisotropy and formation dip, adding the symmetrical directional measurements together maximizes the sensitivity to bed boundaries, which is optimal forgeo steering. The fact that the antennas are mounted on a conductive collar significantly reduces the large borehole effects that are normally associated with transverse EM measurements in conductive mud. In addition to exploring the physics of the new directional propagation measurements, we will demonstrate their unique applications with field test examples. By detecting and tracking, in real time, formation boundaries up to 15 ft around the wellbore, the directional propagation tool allows for sufficient time to make trajectory adjustments and stay within the reservoir. The bedding orientation information also answers the question, in what direction to steer, which is often ambiguous when relying on traditional propagation measurements. Particularly interesting applications are the placement of wells in thin oil rims and in reservoirs with complex structures such as intra-bedded shale silts. Field test examples will also be shown of the enhanced formation evaluation capabilities offered by directional measurements in high-angle and horizontal wells, where formation resistivities can now be determined while accurately accounting for proximate bed boundaries. The ability to measure resistivity anisotropy in near vertical wells will be demonstrated by a field test example where the anisotropy measurement was confirmed by comparing with a conventional propagation resistivity measurement run in a near-by high-angle well.

Biography:

Cuiwei Liu is currently pursuing his PhD in Oil and Gas Storage and Transportation Engineering from China University of Petroleum. His research emphases include leak detection and location for oil and gas pipelines based on acoustic waves and dynamic pressure waves.

Abstract:

In order to study a new leak detection and location method for oil and natural gas pipelines based on acoustic waves, the propagation model is established and modified. Firstly, the propagation law in theory is obtained by analyzing the damping impact factors which cause the attenuation. Then, the dominant-energy frequencies bands of leakage acoustic waves are obtained through experiments by wavelet transform analysis. Thirdly, the actual propagation model is modified by the correction factor based on the dominant-energy frequency bands. Then a new leak detection and location method is proposed based on the propagation law which is validated by the experiments for oil pipelines. Finally, the conclusions and the method are applied to the gas pipelines in experiments. The results indicate that the modified propagation model can be established by the experimental method; the new leak location method is effective and can be applied to both oil and gas pipelines and it has advantages over the traditional location method based on the velocity and the time difference. Conclusions can be drawn that the new leak detection and location method can effectively and accurately detect and locate the leakages in oil and natural gas pipelines.

Biography:

Zhizhong Deng, graduate student of oil & gas well engineering, from the State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University. His research interests are focused on mechanics and chemistry with working fluid of oil and gas well . He has obtained two invention patents and an article listed by SCI.

Abstract:

A new inorganic gel plugging fluid system that is solidifiable as plug in loss zone has been developed, so as to treat the following problems occurring in malignant lost circulation. Blocking material in mud lialbe to accumulating on the wellbore where channels causing circulation loss are existed (Door Sealed Phenomenon), the weak gel fails to improve the stratum bearing capacity substantially, cement plug is susceptible to erosion which results in strength loss in later period and other problems reducing plugging success rate. Unlike adding various conventional chemical treatment agents to plugging fluid system to adjust the mud performance, we studied the impact on the system of sedimentation stability, rheology, compressive strength, etc. by changing the percentage of the component substances, such as bentonite, CaO, MgO, and Al2O3 and analyzing the test samples and microstructure via X-Ray Diffractometer (XRD) and Scanning Electron Microscope (SEM). The analysis indicates that: a)bentonite can effectively adjust the sedimentation stability and shear thinning behavior; b)components of the curing agent like CaO and MgO can increase the compression resistance of the sample; c)such activators as NaOH, Na2CO3 and Na2SiO3 adjusts the rheology by changing the hydration film thickness of the charged particles; d)alkaline environment causes the vitreum of the curing agent disperse, dissolve and form the structure of solidifying working fluid to plug. The field case of Well MX001-X proves that the system can be applied in different wells by adjusting the additives in case loss occurs to oil/gas wells.

Biography:

Obi Williams J D is a Lecturer in the School of Industrial and Technical Education of the Federal College of Education (Technical) Umunze in Anambra State Nigeria. He has put in over 15 years in tutoring, research and community service and served the institution as Head of Department, Electrical and Electronics as a research advisor and project supervisor.

Abstract:

Oil and gas resources are Nigeria is located in the Niger Delta which is situated in the Gulf of Guinea. The Niger Delta is a sedimentary basin having only one identified petroleum system (Akata –Agbada). It is formed at the site of a rift triple junction related to the opening of the southern Atlantic starting in the Late Jurassic and continuing into the Cretaceous. It has an accumulated sedimentary cover of up to 10 km at some places. Oil is produced from sandstone facies within the Agbada Formation. An estimated 34.5 billion barrels of recoverable oil and 93.8 trillion cubic feet of recoverable gas have been discovered in the Niger Delta. Due to poor infrastructural development in the area, accessibility is often hampered, exposing valuable assets, equipment and installations to pipeline vandals and oil thieves, with fewer restraints from the law enforcement agencies. The paper discusses a remote monitoring system based on GSM technology that monitors the critical oil and gas industrial parameters and sends alerts and text messages when the preset conditions are reached or exceeded to the designated addresses as an advanced means of circumventing the identified lapses in oil equipment and installation security by the researchers. The work is realised by the interface of three major blocks of input unit, the host controller and the output unit. Software programme were written and developed to drive the system. From the analysis and results of various tests carried out, the paper concluded that the implemented technology for the system is capable of delivering the expected performance and desired reliability level

Biography:

Abstract:

Direct combustion of Jordanian oil shale under oxy-fuel conditions is the first of its kind. Unstaged and staged air-firing as well as combustion at 27% O2/73% CO2 (OF27) was conducted successfully. A 20 kW vertical reactor was used at a combustion temperature of 1200ºC. Oil shale- N conversion rate to NO is higher during unstaged air-firing than oxyfuel combustion; they are 27% and 15% for air-firing and OF27 combustion, respectively. NOx emission can be reduced efficiently by adopting staged combustion technology under oxy-fuel conditions as well as air-firing. In addition, the reduction of simulated recycled NO has been investigated. The actual situation has been simulated by injecting NO in the reactor through the burner. The reduction of the injected NO is more efficient with staging compared to unstaged combustion mode for both air-firing and oxyfuel combustion; the reduction of the injected NO during staged air-firing and OF27 is 100%. During unstaged air-firing the reduction of the injected NO ranges from 61% to 66%, while for unstaged OF27 combustion it ranges from 57% to 65%. The high sulphur content in Jordanian oil shale is considered one of the biggest challenges for its utilization. The oil shale- S conversion rates to SO2 is lower during unstaged oxyfuel combustion compared to air-firing; they are 69% and 49% for air-firing and OF27 combustion, respectively. Direct limestone injection at different molar Ca/S ratios has been investigated under unstaged oxyfuel conditions as well as air-firing. Significant reduction in SO2 emissions is obtained by limestone injection in both combustion modes. At Ca/S molar ratio of 3, the desulphurization efficiencies are 95% and 100% for air-firing and OF27 combustion, respectively.

Biography:

Amin Soleimani mehr has completed his M.sc at the age of 23 years from Petroleum University of Technology and Starts cooperating with National Iranian Gas Co-Department of Operation. Considering his deep studies on MTO process and catalyst had several successful academic and industrial projects such as SAPO-34 Industrial Catalyst production used in MTO in Petroleum University of Technology ordered by National Iranian Petrochemical Co.-Research and Technology.http://oil-gas.conferenceseries.com/

Abstract:

Concerning Natural Gas reserves all around the world, Syngas -as a product- was decided to be the most important intermediate cut. Transport difficulties, hazards and safety made main Energy suppliers to replace and Supply Methanol for production and Export. This policy changed the balance in Global consumption and production of Methanol leads to a serious change in its pricing. Polymer demand in industrial countries prepared a powerful desire for new Methanol to Hydrocarbon (especially Ethylene and Propylene) processes desire. Lurgi, first proposed a process generates Dimethylether at the first reaction, then converts it to alpha olefins (Propylene mainly) and a light liquid cut. Two main catalysts were used for this process were Gamma-Alumina and ZSM-5. This process was also modified to a direct synthesis form leads to Methanol to H.C. Mobil developed this process to a qualified process which was supposed to use a continuous regeneration fluidized bed reactor in 1977. This new developed process was later managed and redesigned by UOP. The main Catalyst used for MTO was SAPO-34 (Chabazite). After 2000 hours literature study, our team in Petroleum University of Technology started its work on MTO over alkali modified ZSM-5 leads to a main process study and finalizing the optimum reaction condition. Resulted paper was published in Fuel (Elsevier). Then promotion was performed using Se, Ce, K and Cs. Then SAPO-34 synthesis was finalized in 20 main methods and process was studied delicately. Finally, the best Catalyst batch and method was promoted using 12 main active metals

Biography:

E. Nemati Lay, Assitant professor of chemical engineering at the department of chemical engineering at the University of Kashan

Abstract:

This study presents a new pressure gradient correlation for oil-water dispersed flow in horizontal pipes. The new model was derived from 225 experimental pressure gradient data points for variety range of Reynolds number (Rem =2300-1×105) and mixture velocities (Um=0.5-4 m/s). The accuracy of this new model has been evaluated against the homogeneous model. The comparison indicates that the new proposed correlation predicts the pressure gradient with higher accuracy than the homogeneous model.

Biography:

Abstract:

Corrosion tests of carbon steel in two phase flow of liquid–gas (CaCO3 solution -CO2 gas) under different operating conditions of temperatures, agitation velocity, gas flow rate, and time were investigated using electrochemical polarization technique. Flat blade disc turbine mixer was used to simulate the two phase flow conditions. Cathodic protection was used to protect carbon steel in salt solution-CO2 mixture by using zinc as sacrificial anode under different operating conditions of flow rate of CO2, agitation velocity, and temperature by measured corrosion potential and weight loss method. The corrosion rate represented by limiting current density (iL) in two phase brine-CO2 mixture, decreases with the increase in agitation velocity depending on flow rate of CO2, temperature, and time. In general, increasing CO2 gas flow rate caused a clear decrease in corrosion rate especially at high agitation velocity. Good corrosion protection percent was attained which under not sever corrosion conditions reached to 85%. In addition, the variations of corrosion potential with time for both metals (CS and Zn) were determined as well as the loss in weigh for each metal.

Biography:

Abstract:

Natural gas is the clean energy that has been extensively used for several purposes primarily in transportation and generation of electricity. The major constituents of natural gas are CH4 and CO2. The absorption/stripping of carbon dioxide is an important task in the operation of gas–liquid membrane contacting processes. The removal of CO2 from natural gas prior to use is essential. The presence of CO2 reduces the heating value of the natural gas and causes pipe corrosion. The conventional absorption processes are packed columns. The packed towers are usually large in size, require high investment cost and suffer from several operational limitations include flooding, entrainment and foaming. Recently hollow fiber membrane contactor has attracted the attention of many researchers. Absorption of CO2 takes place in a membrane contactor when the gas stream contacts with the liquid phase flowing on the opposite side of the membrane. Various absorbents on CO2 absorption/stripping were investigated; potassium glycinate (PG), monoethanolamide (MEA), di-ethanolamine (DEA), and 2-amino-2-methyl-1-propanol (AMP) were applied as absorbent/stripping solutions. The membrane used for the experiments was hollow fiber Polyvinylidenefluoride (PVDF) membrane fabricated via thermally induced phase separation method. The performances of various amine solutions on the CO2 absorption/stripping capability were investigated. CO2 stripping experiments revealed that regardless of type of solvent the CO2 stripping flux and efficiency rapidly increases with liquid temperature, pressure and initial CO2 concentration.