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Collaborating Authors
Results
An Experimental Investigation of Polysilicon Nanoparticles’ Recovery Efficiencies through Changes in Interfacial Tension and Wettability Alteration
Roustaei, Abbas (Abadan Institute of Technology (AIT)) | Moghadasi, Jamshid (Abadan Institute of Technology (AIT)) | Iran, Abadan (Research Institute of Petroleum Industry (RIPI), Tehran, Iran) | Bagherzadeh, Hadi (Research Institute of Petroleum Industry (RIPI), Tehran, Iran) | Shahrabadi, Abbas (Research Institute of Petroleum Industry (RIPI), Tehran, Iran)
Abstract New technologies are emerging oil industry to afford the need for increasing oil recovery from oilfields, one of which is Nanotechnology. This paper experimentally investigates a special type of Nanoparticles named Polysilicon ones which are very promising materials to be used in near future for enhanced oil recovery. There are three types of Polysilicon Nanoparticles which can be used according the reservoir wettability conditions. In this paper, hydrophobic and lipophilic polysilicon (HLP) and naturally wet polysilicon (NWP) are investigated as EOR agents in water-wet sandstone rocks. These two Nanoparticles recover additional oil through major mechanisms of interfacial tension reduction and wettability alteration. The impact of these two Nanoparticle types on water-oil interfacial tension and the contact angle developed between oil and the rock surface in presence of water phase were investigated. Then, several coreflood experiments were conducted to study their impacts directly on recoveries. Furthermore, optimum pore-volume injection of each Nano-fluid was determined according the pressure drop across the core samples. The results show a change toward less water-wet condition and a drastic decrease in oil-water interfacial tension from 26.3 mN/m to 1.75 mN/m and 2.55 mN/m after application of HLP and NWP Nano-fluids respectively. As a result, oil recoveries increase by 32.2% and 28.57% when a 4 gr/lit concentration of HLP and NWP Nano fluids are injected into the core samples respectively. According the differential pressure data, two and three pore-volume injections of NWP and HLP Nano-fluids are the best injection volumes respectively. Finally, HLP and NWP Nanoparticles improve oil recovery without inducing any formation damage according the oil recovery and pressure drop data.
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.49)
- Overview (0.48)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.97)
Nano-Enhancement of Barrier Coatings for Improved Downhole Performance of Oilfield Materials
Welch, John C. (Vu Thieu of Baker Hughes) | Newman, Caleb (Vu Thieu of Baker Hughes) | Gerrard, David (Vu Thieu of Baker Hughes) | Mazyar, Oleg A. (Vu Thieu of Baker Hughes) | Mathur, Vipul (Vu Thieu of Baker Hughes)
Abstract The oil and gas industry is continuously looking for robust material and tool designs that provide greater operational flexibility in aggressive environments. Coating systems, engineered at the nanometer scale, exhibit enhancements that can address these needs. Our study of nano-engineered coatings started with simple polymer-polymer self-assembled systems, to which was added nano-sized clay or one of several carbon-based nano materials. We evaluated application of different cross linker treatments. To evaluate the variables involved in preparation of the coating systems we quantified thickness and contact angle, and we performed micrographic and scanning electron microscope analysis of standard coated substrates. When applied to copper coupons we determined a 91% reduction of corrosion after four hours, 60% after 24 hours, and 13% after ninety hours in a hydrogen sulfide gas blend. Nano-engineered coatings applied to common oilfield elastomeric materials produce a 40x delay in swelling and decrease in transmission of carbon dioxide gas by 73%. All of the above are lab results, and the comparisons were made to baseline commercially available rubber compounds without nano-enhancement. Our results demonstrated that nanotechnology can be very effectively used to significantly modify properties of commonly used oilfield materials. Reduced corrosion can extend the life of downhole electronics and motors. The oil swelling rate can be drastically reduced to give operators a greater flexibility in setting the packers and reducing intervention. These findings can be used to design new packers, sealing elements and other elastomeric components used in downhole environment. This paper will present our recent lab results along with a postulated mechanism on how nanotechnologies can impact material performance in downhole applications.
- Europe (0.46)
- North America > United States (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract When newly drilled oil and gas wells fail to reach the expected production levels, near-wellbore damage may have resulted from fluid incompatibility, poor fluid/rock interaction and/or mechanical damage. These problems may also occur during remediation or stimulation operations, if the treatment fluid is not properly designed. The principal formation damage mechanisms that lead to these problems are in-situ emulsions, wettability changes, water blocks and scale formation. It is recognized that such reservoir damage can be removed or prevented using microemulsion technology that leads to more productive oil and gas wells. The challenge is to design and select an optimized microemulsion system based on the reservoir conditions, such as the bottomhole temperature and the individual compositions of the crude oil, formation water, and the drilling and completion fluids. A well-designed treatment fluid should provide ultra-low interfacial tension, high oil solubilization and total compatibility with all fluids it encounters. The selection of the optimum formulation for a specific application requires a systematic study of the phase behavior of brine-surfactant-oil systems as a function of temperature and its final composition, including the salt, surfactants, co-surfactants and an optional acid. This paper provides a comprehensive discussion of the phase behavior obtained with the brine/surfactant/oil systems used in microemulsion formulations for formation damage prevention and removal. Laboratory tests results and field applications in openhole and cased-hole completed wells have proven that the microemulsion treatment fluids are successful in the field, if there is a systematic analysis of phase behavior that identifies and defines the treatment fluid phase boundaries.
- North America > United States (0.94)
- Africa > Cameroon > Gulf of Guinea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Wettability Determination by Equilibrium Contact Angle Measurements: Reservoir Rock- Connate Water System With Injection of CO2
Shojai kaveh, N.. (Defalt University of Technology) | Berentsen, C. W. (Defalt University of Technology) | Rudolph, E. S. (Defalt University of Technology) | Wolf, K-H. A. (Defalt University of Technology) | Rossen, W. R. (Defalt University of Technology)
Abstract The injection of carbon dioxide (CO2) into depleted gas reservoirs and aquifers offer options for CO2-storage. CO2 sequestration is largely controlled by the interactions between CO2, reservoir fluid(s) in place and rock. In particular, the wettability of the rock matrix is a key factor for the fluid distribution and fluid displacement. In this study, the wetting behavior of CO2-Bentheimer sandstone-water systems was investigated by means of visual contact-angle measurements. The experiments were conducted in a modified pendant drop cell (PDC) that allows captive-bubble contact-angle measurements at elevated temperatures and pressures. Contact angle measures were peformed with water that was fully (pre)-saturated with CO2. Multiple experiments were performed at constant temperature of 318K and pressures varying between 0.1-12 MPA which represent typical in-situ reservoir conditions. The experimental data shows that the contact angle and the size of the bubble converge to equilibrium in time. During this convergence period, the contact angle and the bubble size generally show a slight change as function of time. This can be contributed to the mass transfer and reduction in density of the CO2 during re-equilibration of the system. The experimental data shows a larger dependency of the contact angle on bubble size than on pressure. However, for bubbles with similar size, contact angle shows a slight increase as a function of pressure. However, for bubbles with similar size, contact angle shows a slight increase as function of pressure. All data shows that Bentheimer-water-CO2 systems remain water-wet even at high pressure.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Abstract Proper acid placement/diversion is required to make matrix acid treatments successful. Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore. Spreading droplets may not reflect wettability, if they result from low oil-acid IFT's. Therefore, a procedure was proposed for contact angle measurements when surfactant solutions, such as spent acid with VES and EGMBE,reduce interfacial tensions (IFT's) and cause oil droplets to spread (Adejare et al. 2012). The effect of two amphoteric amine-oxide VES', designated as "A" and "B", and an EGMBE preflush and postflush on the wettability of Austin cream chalk was studied using the proposed procedure.In addition, the two-phase titration experiment was used to measure VES adsorption. A treating schedule sequence typical of carbonate matrix acidizing was used. Rocks were centrifuged in fluids representing the preflush, main acid stage, diverting stage, and postflush.The difference in contact angles before and after centrifuging shows the effect of surfactants in the spent acid on wettability.Contact angles were measured in spent acid with HCl only to prevent VES and EGMBE from reducing IFT's. VES "A" and "B" adsorb on the rock surface at 25 and 80°C.Experiments with acid treatments with 4 vol% VES "A" and "B" diversion stages and a 10 vol% EGMBE preflush and postflush made initially oil-wet rocks water-wet at 25°C, 80°C, and 110°C. Acid treatments with a 4 vol% VES "A" diversion stage only made rocks water-wet at 25°C and 80°C. For the parameters investigated, our results suggest that diversion with VES "A" only, andan EGMBE flush following diversion with VES "A" and "B",can alter wettability to water-wet and increasethe relative permeability to oil.
- North America > United States > Texas (0.94)
- Europe (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.85)
Abstract Manipulating the injected brine composition can favorably alter the reservoir wetting state; this hypothesis has been validated in sandstone reservoirs by several scientists. A total of214 coreflooding experiments were conducted to evaluate low salinity waterflooding (LSWF) secondary recovery and 188 experiments were conducted to evaluate tertiary recovery, for sandstone reservoirs. Although the incremental recovery potential in carbonate reservoirs is greater than in sandstones, only a few imbibition and coreflooding experiments have been conducted. The simulator and recovery mechanisms presented by Aladasani et al. (2012) are used and their suitability and validity to low salinity waterflooding in carbonate reservoirs has been confirmed. This has been achieved by comparing simulated LSWF secondary and tertiary recoveries with published coreflooding experiments. Furthermore, the prediction profiler in JMP was used to examine incremental recovery for the following variables: (a) acid number and interfacial tension (IFT) sensitivities, and (b) 2 stage injected brine and 3 stage injected brine anion contents. In weak water-wet conditions, the incremental recovery is driven by low capillary pressures, and the underlining recovery mechanism is the increase in oil relative permeability. Therefore, wettability modification is ideal when achieved by shifting the wetting state from oil-wet or water-wet to a maintained intermediate wetting condition irrespective of the injected brine salinity dilution. If the wettability is shifted to a strong water-wet system, then it would be more favorable to use brine with anions to shift the wettability back to an intermediate wetting state. IFT has a bigger impact on LSWF in carbonate reservoirs; however, contact angle is more significant to the final oil recovery. Future work should consider studying the impact of cationic and anionic ions on coreflooding recovery separately and using cores with different initial wetting states, preferably strong oil-wet cores.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.28)
- North America > Canada > Alberta (0.28)
Abstract The primary purpose of using surfactants in stimulating hydrocarbon rich gas reservoirs is to reduce interfacial tension, and/or modify contact angle and reservoir wettability. However, many surfactants either adsorb rapidly within the first few inches of the formation, or negatively impact reservoir wettability, thus reducing their effectiveness in lowering capillary pressure. These phenomena can result in phase trapping of the injected fluid adversely impacting oil and gas production. This study describes experimental and field studies comparing various common surfactants used in oil bearing formations including alcohol ethoxylates, EO-PO block copolymers, ethoxylated amines and a multi-phase complex nano fluid system to determine their impact on oil recovery and adsorption tendencies when injected through 5-foot and 1 ft sand columns. Ammot cell tests were used to evaluate imbibition of oil and water and a core flow apparatus was used to evaluate regained relative permeabilities. The results are correlated with surface energies of actual formation materials, oils and treating fluids. The results are used to select formulations containing surfactant, solvents and co-solvents to apply within the fracturing fluid to decrease adsorption, eliminate post treatment emulsions and improve oil and gas recovery in hydrocarbon rich gas wells.
- North America > Canada (0.69)
- North America > United States > Texas (0.46)
- North America > United States > West Virginia (0.28)
- (2 more...)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (11 more...)
Abstract The goal of this work is to pursue strategies to improve oil recovery in highly fractured carbonate reservoirs by altering the wettability from oil-wet to preferentially water-wet at high temperature (100°C or above), high salinity, and especially high hardness environments. Cationic surfactants and anionic surfactants were investigated for their compatibility with hard brine and thermal/hydrolytic stability. Sequestration agents were added to improve aqueous solubility. The performance of surfactant formulations was evaluated by measuring contact angles on calcite plates and spontaneous imbibition in originally oil-wet dolomite cores. Cationic surfactants altered the wettability of oil-aged calcite plates towards a more water-wet state in the presence of hard brines; oil recovery by spontaneous imbibition from dolomite cores was 50–65% OOIP. Anionic surfactant formulations changed the carbonate wettability to strongly water-wet only when the brine salinity and divalent ion concentration were reduced. The wettability could be altered in hard brines if a sequestration agent (e.g. EDTA) is added to anionic surfactant formulations; up to 45% OOIP was recovered by spontaneous imbibitions. EDTA provides alkalinity, saponification, chelation of divalent ions, and dissolution of dolomite; these mechanisms are responsible for the increase in imbibition rate and ultimate oil recovery in fractured carbonates.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.99)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- (3 more...)
Abstract Wettability modification of solid rocks by using surfactants is an important process that is used in practical applications such as oil recovery from reservoirs. When wettability is altered, both capillary pressure and phase relative permeability change wherever the porous rock is contacted by surfactant. Due to the complexity of reservoir rock, alteration of the wettability is not uniform throughout the swept area. Although there are several numerical studies in the literature to simulate the effect of wettability alteration on oil recovery from oil-wet rock systems, these wettability alteration models permit alteration of the rock wettability uniformly and independently from time. Properties such as capillary pressure, oil and water relative permeability, and interfacial tension are calculated by the use of an interpolation scaling factor between two wettability extremes: oil-wet and water-wet. In the present study, a novel time-dependent wettability alteration model is proposed in which the contact angle is correlated to the surfactant concentration through an empirical correlation developed by using experimental data. The model allows the rock wettability to be altered in a heterogeneous manner with time. The proposed model was tested against a number of experimental and simulation results. Very good quantitative agreements between the simulation outcomes and experimental data from the literature were shown. The simulation of surfactant solution imbibition in laboratory scale cores using the proposed new model showed that the wettability alteration should be considered as a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. Also, we found that gravity force is the primary cause of surfactant solution getting into the core and changing the rock wettability toward a less oil-wet state.
- North America > United States > Texas (0.93)
- Asia (0.68)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
Abstract Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore. Receding contact angles were measured to study the effect of spent acid solutions with an amphoteric amine-oxide VES, and the mutual solvent EGMBE on the wettability of Austin cream chalk rocks. However, when oil droplets are injected into spent acid solutions with VES and EGMBE, low oil-acid interfacial tensions (IFT) cause them to spread on the rock surface. Contact angles cannot be measured when droplets spread. In addition, spreading may result from low oil-acid IFT's, rather than indicating strong oil-wetness. A procedure is proposed for contact angle experiments for surfactant solutions that cause oil droplets to spread. Rocks were centrifuged in spent acid solutions with VES and EGMBE. Then, contact angles were measured in spent acid with HCl only, to prevent VES and EGMBE from reducing the oil-acid IFT. The effect of the surfactants in the spent acid on the rock-oil/acid IFT, which is the wettability, is shown by the difference in contact angles before and after centrifuging. Using the proposed procedure, a spent acid solution with HCl, 1 vol% VES and 10 vol% EGMBE made an oil-wet rock water-wet, and a water-wet rock strongly water-wet at 25°C. This suggests that an EGMBE postflush enhances the relative permeability to oil, under the parameters investigated. Contact angles are a function of the rock-oil/acid and oil-acid IFT's. The wettability of the rock is determined by the rock-oil/acid interface. The proposed procedure is effective because, in contrast with the conventional procedure, the oil-acid IFT is kept high and constant, so that changes in the rock-oil/acid interface can be observed. The proposed procedure will be used in future studies of the effect of spent acid solutions with VES and EGMBE on wettability.
- Research Report (0.46)
- Overview (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.87)