Day 2 Wed, April 24, 2019最新文献

{"title":"The Impact of Re-Injecting Flowback Fluids on Formation Damage. Case Study: Marcellus Shale","authors":"Lifu Zhang, M. Tice, B. Hascakir","doi":"10.2118/195336-MS","DOIUrl":"https://doi.org/10.2118/195336-MS","url":null,"abstract":"\u0000 Reuse of flowback water in hydraulic fracturing is usually used by industry to reduce consumption, transportation and disposal cost of water. But because of complex interactions between injected water and reservoir rocks, induced fractures may be blocked by impurities carried by flowback and mineral precipitation by water-rock interactions, which causes formation damage. Therefore, knowledge of flowback water-rock interactions is important to understand the changes within the formation and effects on hydraulic fracturing performance.\u0000 This study focuses on investigating flowback water-rock interactions during hydraulic fracturing in Marcellus Shale Formation. Simple deionized water-rock interactions and complicated flowback water-rock interactions were studied under static and dynamic conditions. In static experiments, crushed reservoir rock samples were exposed to water for three weeks at room condition. In the dynamic experiment, continuous water flow interacted with rock samples through the core-flooding experimental system for three hours at reservoir condition. Before and after experiments, rock samples were characterized to determine the change on the rock surfaces. Water samples were analyzed to estimate the particle precipitation tendency and potential to modify flow pathway.\u0000 Surface elemental concentrations, mineralogy and SEM images of rock samples were characterized. Ion contents, particle size, TDS and Zeta potential in the water samples were analyzed. In both static and dynamic experiments, compared with deionized water-rock interaction, rock samples after being exposed to flowback water show change in the elemental compositions, more fine particles attachment and new minerals detected on rock surface due to effect of flowback water. In produced water, Na, Sr and Cl are extremely high after flowback water-rock interactions because of flowback water contamination. Water parameter analysis indicates after flowback water-rock interactions, suspensions in produced water have highest precipitation tendency because of extremely highest TDS, largest particle size and lowest absolute Zeta potential relative to all water samples. Therefore, according to rock and water characterization, if flowback water without any treatment would be reused in the field hydraulic fracturing operation, created flow pathways and pores are more likely to be blocked and formation damage will be caused.\u0000 This study provides information on comparison between deionized water-rock interaction and flowback water interaction. The information enhances the understanding of basic water-rock interaction mechanisms and evaluates formation damage caused by reuse of flowback water.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125149719","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of Novel Surfactants with Co-Solvent Character for Heavy Oil Recovery","authors":"K. Baek, F. J. Argüelles-Vivas, Gayan A. Abeykoon, R. Okuno, U. Weerasooriya","doi":"10.2118/195345-MS","DOIUrl":"https://doi.org/10.2118/195345-MS","url":null,"abstract":"\u0000 A new class of ultra-short hydrophobe surfactants with co-solvent character was investigated as a sole additive to conventional polymer flooding for heavy oil recovery. No alkali was used for emulsification. The surfactants tested are composed of a short hydrophobe (phenol in this research) extended by a small number of propylene oxide (PO) and sufficient ethylene oxide (EO) units to achieve aqueous stability: phenol-xPO-yEO. Results are presented for the selection of ultra-short hydrophobe surfactants, aqueous stability, emulsion phase behavior, and oil-displacement through a glass-bead pack at 368 K.\u0000 Results show that 2 wt% phenol-4PO-20EO was able to reduce the interfacial tension between oil and NaCl brine to 0.39 dynes/cm, in comparison to 11 dynes/cm with no surfactant, at 368 K. Water flooding, 70-cp polymer flooding, and surfactant-improved polymer flooding were conducted for displacement of 276-cp oil through a glass-bead pack that represents the clean-sand faces of a heavy oil reservoir in Alberta, Canada. The oil recovery at 2 pore-volumes of injection was 84% with the surfactant-improved polymer flooding, which was 54% and 22 % greater than the water flooding and the polymer flooding, respectively. Results suggest a new opportunity of enhanced heavy oil recovery by adding a slug of one non-ionic surfactant with co-solvent character to conventional polymer flooding.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"90 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134522431","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Modified Design for Gravel Packing with Expandable Rubber Beads","authors":"M. Ramezanian, H. Emadi, Hong Wang","doi":"10.2118/195293-MS","DOIUrl":"https://doi.org/10.2118/195293-MS","url":null,"abstract":"\u0000 In oil and gas wells with sand control completion, during gravel pack installation and production life of the well, void spots - known as hotspots - may form in gravel packs. Hotspots provide permeable channels within the pack that allow sand to pass into the wellbore and consequently loosen the pack. Finding an innovative way to prevent hotspots from forming maintains the gravel pack integrity and preserves its efficiency. Indeed, this approach would save money by reducing the demand for remedial operations. This paper introduces, a modified design for gravel packing with expandable rubber beads. The new pack is composed of gravel and expandable rubber beads rather than 100% gravel and is capable of avoiding the hotspots and maintaining pack tightness. A series of experiments were conducted, with diesel, on 100% expandable rubber bead packs and mixtures of gravel and bead to measure their swelling capacity and permeability. The swelling volume was evaluated to assess the beads capacity to fill the hotspots and permeability was measured to assess their potential to create flow barrier. The tests show promising permeabilities for gravel/rubber bead packs and reasonable expansion potential to fill the hotspots. Increasing the proportion of the beads in gravel/rubber bead mixture pack, results in very low permeability. Hence, finding an optimum proportion of rubber beads is essential to designing a pack that will take advantage of their swelling capacity to avoid hotspots while retaining reasonable permeability toward the flow.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"77 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134040537","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluation of a New Treatment to Remove Calcium Sulfate Scale: Lab Studies and Field Application.","authors":"A. Ibrahim, H. Nasr-El-Din, Mohamed Abd El-baqi, A. Abdelhay, H. Farouk, A. Aref, Ahmed Reda, M. Rafaat, M. Gamal","doi":"10.2118/195313-MS","DOIUrl":"https://doi.org/10.2118/195313-MS","url":null,"abstract":"\u0000 Scale deposition has been a significant problem in the oil and gas industry. Scale deposition has an adverse impact on production and injection operations. The precipitation of scale in the near-wellbore area will diminish the productivity of the production wells and loss of the injectivity of water injection wells. This paper presents a new non-corrosive agent to remove calcium carbonate, and calcium sulfate scales.\u0000 Two sets of coreflood experiments were conducted to evaluate the chemical to remove anhydrite depositions. Coreflood experiments were conducted by using the new scale remover to stimulate dolomite cores with anhydrite content of 30 wt% at 250°F. Other experiments were conducted with the Bandera sandstone cores. Calcium sulfate was precipitated inside the pores and then the chemical was used to treat the cores to remove this damage. Effluent samples were collected and analyzed with ICP for sulfur and calcium concentrations. CT scan was used to detect the dissolution and the deposition of scale inside the cores. The chemical was applied on several oil wells from the Nukhul sandstone formation.\u0000 Coreflood results show increasing the permeability of the dolomite core to 4 times of its initial value and ICP results show 1:1 calcium to sulfur concentrations. The second coreflood experiments showed the ability of the dissolving agent to remove the precipitated scale completely with (final permeability =initial permeability) with no effect on clays. In the field case, the treatment was conducted and placed using a coiled tubing without using additional additives such as corrosion inhibitors, intensifiers, and iron control agents. The success of this treatment was realized by increasing the well production 4 times its initial oil production per day.\u0000 Field data and the lab results highlight that the de-scaling solution is an effective fluid for calcium sulfate scale.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125106065","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"First Ever Polymer Flood Field Pilot - A Game Changer to Enhance the Recovery of Heavy Oils on Alaska’s North Slope","authors":"A. Dandekar, B. Bai, J. Barnes, D. Cercone, J. Ciferno, S. Ning, R. Seright, B. Sheets, Dongmei Wang, Yin Zhang","doi":"10.2118/195257-MS","DOIUrl":"https://doi.org/10.2118/195257-MS","url":null,"abstract":"\u0000 The development pace of Alaska's vast, 20-25 billion barrels, heavy oil resources has been very slow due to high development costs and low oil recovery using conventional waterflood, and the impracticality of deploying thermal methods due to the presence of continuous permafrost. Although, polymer flooding has attracted attention and has become a promising EOR technique in heavy oil reservoirs due to the extensive application of horizontal wells and advancement of polymer flooding technology, no field tests have been performed to date in Alaska's underdeveloped heavy oil reservoirs. The overall objective of this research is to perform a field experiment to validate the use of polymer flooding for extracting heavy oil in Alaska's challenging environment.\u0000 Two pre-existing pairs of horizontal injection and production wells in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field are currently being used for the field experiment. Hydrolyzed polyacrylamide (HPAM) polymer injection started on August 28, 2018 at 600 ppm (4 cP viscosity) concentration ramping up to 1,800 ppm (45 cP viscosity) over a three week time period, and has been maintained at an average concentration of ~1,800 ppm. Current injection rates in the two horizontal injectors are ~2,200 and 600 bwpd. Laboratory experiments to determine the polymer retention, optimum water salinity, synergistic effects of water salinity and polymer, and handling of produced fluids, in support of the field experiment, are currently ongoing. Similarly, reservoir simulation of coreflood behavior and history match of previous waterfloods to predict polymer flood performance in the project area are also conducted in parallel.\u0000 The field data and scientific knowledge that have been collected since the start of the injection indicates that the field pilot is performing as predicted. To date, no unexpected injectivity issues or polymer breakthrough have been encountered, and the two horizontal producers are showing positive response to the polymer injection, resulting in incremental increase in oil production rate. Since the research is still in its early stages, selected field, laboratory and simulation results are presented and discussed to highlight the integrative approach adopted in this first ever polymer flood field pilot in Alaska.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"169 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115955070","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of Sourceless Solutions for Geosteering and Formation Evaluation with Logging While Drilling Technologies: Case Study from Kuwait Reservoir","authors":"G. S. Padhy, T. Gezeery, Mohamed Al Rashidi, Jeevankumar Silambuchelvan, Tahani Al Rashidi, Anar Abdulkarim, N. Farhi, Huseynagha Rahimov","doi":"10.2118/195289-MS","DOIUrl":"https://doi.org/10.2118/195289-MS","url":null,"abstract":"\u0000 An emerging technology called sourceless well placement and logging (without using traditional chemical radioactive sources) has intensified in recent years because of various factors, such as drilling risk reduction and cost optimization, as well as evolving government regulatory and health, safety, and environment (HSE) requirements.\u0000 Established technologies, such as acoustic sensors, have been tested during pilot projects in several Middle Eastern development environments to evaluate the viability of replacing conventional density-neutron sensors. Current developments and integrated workflows are encouraging for the provision of sourceless well placement, porosity, and petrophysical and geomechanical evaluations for some of the mature reservoirs. These developments include a substantial number of case histories already established in clastic and carbonate depositional environments for the previous five years.\u0000 The current well was planned through carbonate and clastic sequence as part of a geological section deemed important from a borehole stability point of view. Borehole deterioration and significant variations in pore pressure were also considered to increase the potential risk for the drillstring sticking. Conventional porosity tools used during a logging while drilling (LWD) bottomhole assembly (BHA) with radioactive sources exacerbate the potential risk at an environmental-hazard level. Additionally, retrievable-based sources can be problematic during extraction in high-angle wells. LWD azimuthal-acoustic tools free of radioactive sources were run for porosity measurements, pressure prediction, geomechanics, and possible anisotropy using a centralized four-axis acoustic caliper. A comprehensive petrophysical interpretation was also performed as part of the horizontal build section using acoustic porosities in comparison to its nuclear counterparts acquired in different modes. Permeability was deduced from acoustic and high-resolution microimaging data.\u0000 This paper discusses the planning, design, and use of acoustic tools as part of the BHA and the viability, integrity, limitations, and reliability of logged data and interpreted results. The integration of petrophysical data with cutting analysis is investigated to optimize real-time drilling operations and petrophysical data acquisition requirements for improvement of future developments and overall reservoir management strategies.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114939242","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Novel Meshing Routine for Modeling Reservoirs with Multiple Curved and Intersecting Faults in Coupled Flow-Geomechanical Dual 3D Grids","authors":"Abdulrahman Bubshait, B. Jha","doi":"10.2118/195256-MS","DOIUrl":"https://doi.org/10.2118/195256-MS","url":null,"abstract":"\u0000 We use a novel meshing routine to build a coupled flow-geomechanical model of injection and production in a caprock-reservoir-basement system with two conjugate curved faults that resemble a horst-graben or a synthetic-antithetic fault structure. The routine provides the 3D coordinates of each corner in the grid in a CMG grid file format. Our workflow enables us to represent the two faults as 3D objects to which we assign actual physical properties and dimensions of the faults. This is highly advantageous because traditional structured grids cannot represent curved faults, connected faults, or fault intersections without sacrificing either their geometry or their hydromechanical properties. Sacrificing the curved geometry of faults results in a loss of accuracy in computing the induced stresses in the basement region, which is known to host most of the recorded induced seismic events in US. The generated grid was used in a poro-elastoplastic simulation to examine stress changes resulting after production from a reservoir located in the hanging wall block (graben) region bounded by the two conjugate faults. The change in pore pressure due to production causes changes in both the total stress and the effective stress in the reservoir and the basement. The evolution of the shear and effective normal stresses on the faults may induce fault failure and slip depending on the fault rheology and friction parameters.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129952857","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Novel Technology for Providing Long Term Scale Prevention in an Alaskan North Slope Waterflood","authors":"A. Bond, T. Palisch, J. Leasure","doi":"10.2118/195326-MS","DOIUrl":"https://doi.org/10.2118/195326-MS","url":null,"abstract":"\u0000 Most North Slope Alaska oilfields undergo waterflood for pressure maintenance and improved oil recovery. Both recycled produced water, as well as treated seawater are injected into the reservoir which then mixes with connate water in the formation. The combination of seawater with connate water in the reservoir can lead to severe barium sulfate and calcium carbonate scaling in the production wells and reservoir. The scaling is particularly severe at initial breakthrough of the waterflood front in the production wells. However, since water breakthrough timing is unknown, most scale inhibition techniques commence after observing first water production, which is often too late. This scaling can cause significant production losses, leading either to costly remediation with acid, or in the case of barium sulfate, may be impossible to repair.\u0000 A novel scale inhibition technology which uses scale-inhibitor infused proppant has been applied to mitigate scale in other North American oil and gas fields. Unlike the North Slope fields, most of these wells must be inhibited from first production to prevent scale formation from the start. The technology uses a novel process whereby scale inhibitor is only released when it comes in contact with water, making it a choice option for use in North Slope fields where scale inhibitor must be in place at waterflood breakthrough, which is typically unknown. One operator elected to install this technology in the Oooguruk field in Alaska.\u0000 The Oooguruk field is an undersaturated oil reservoir found on Alaska's North Slope. Development includes both production and water injection wells, arranged in a line-drive pattern. Wells are drilled horizontally and completed with multistage hydraulic fracture treatments, which are designed to create longitudinal fractures along the wellbore. Water injection is initiated in the injectors immediately after post-frac flowback operations. Based on the severe scaling observed in other area fields, engineers deemed it imperative to put a plan in place to address scaling when waterflood breakthrough occurred. Since these are horizontal wells, scale remediation is difficult (if not impossible) to perform once the scaling damage has occurred. To address this problem, the novel scale inhibitor proppant technology was incorporated in the hydraulic fracture treatments of the producers. Four wells employing these treatments were successfully completed in 2015 and 2016. Testing of the water during the fracture clean-up period showed inhibitor returns as expected, tailing off as the load water was produced. In early 2018, the first waterflood breakthrough occurred on several wells, and the produced water was analyzed and found to contain inhibitor levels above the minimum designed inhibitor concentration, thereby successfully providing immediate scale inhibition to the entire wellbore. This paper will review the proppant delivered scale inhibitor technology, document the field application includ","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131409566","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Production Optimization through Intelligent Wells in Steam Trapping in SAGD Operations","authors":"C. Temizel, C. H. Canbaz, Yildiray Palabiyik, M. Irani, Karthik Balaji, R. Ranjith","doi":"10.2118/195361-MS","DOIUrl":"https://doi.org/10.2118/195361-MS","url":null,"abstract":"\u0000 Steam-assisted Gravity Drainage (SAGD) is one of the major thermal recovery methods for heavy oil. Optimization of SAGD is a delicate process that needs to be planned and operated in a detailed manner. Steam trapping is one of the methods that may help optimize production in SAGD by keeping the steam chamber well drained, where liquid does not accumulate on top of the producer and steam is not produced. This is a challenging process even with the advances in well completions with smart or intelligent wells. In this study, the use of smart valves (ICVs) are investigated and their use in optimization of SAGD through steam trapping is outlined.\u0000 A comprehensive review on steam trapping, in terms of theory and practice, has been provided. A smart well configuration with intelligent valves are built in a representative reservoir simulation model where the full-physics commercial reservoir simulator is coupled with an optimization/sensitivity software to optimize the processes and investigate the significance of the key control/decision and uncertainty variables. Different approaches are used in steam trap control; static location, dynamic scanning in time and location, and dynamic scanning in time and specified locations. The results are outlined along with practical aspects of the whole process and operation.\u0000 The results are outlined in a comparative way to illustrate the benefits of smart valves and the key points in utilizing them, including economic aspects of their use for additional recovery and the related costs. Results indicate that intelligent wells may prove useful in optimizing steam trapping in SAGD operations depending on the size of the prize.\u0000 There are several studies on steam trapping. However, there aren't many studies that integrate steam trap control with smart wells. This study investigates the theoretical and practical aspects of steam trapping using intelligent wells, along with outlining the key attributes, decision and uncertainty variables in a comparative way in terms of the steam trap control strategies and economics.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133564400","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Synergistic Effect between Surfactant and Nanoparticles on the Stability of Methane Foam in EOR Processes","authors":"C. Qian, A. Telmadarreie, M. Dong, S. Bryant","doi":"10.2118/195310-ms","DOIUrl":"https://doi.org/10.2118/195310-ms","url":null,"abstract":"\u0000 The major challenge in enhanced oil recovery (EOR) by gas injection is poor volumetric sweep efficiency, mainly due to the high gas mobility and reservoir heterogeneity. Injecting gas as a foam increases sweep efficiency, but maintaining foam stability within the reservoir remains a challenge. This research evaluates the synergistic interaction of one type of nanoparticle and a surfactant to increase foam stability, using the concentration ratio of the two components to tune the affinity of the nanoparticle for the gas/liquid interface. We test the capability of the synergistic two-component system to stabilize methane foam and compare it with foam stabilized by surfactants only. A key distinction is the foam stability upon contact with oil, and we explain the observations in static and dynamic conditions.\u0000 Foam stability was measured both in static (foam height) and dynamic (flow through porous media) conditions. In the static test, foam is generated by the shaking method, and foam texture (bubble size and shape) and the decay of foam height with time are indicators of foam stability. To test static stability in presence of oil, heavy oil is injected into the foam-liquid interface. In dynamic test, foam is pre-generated before flowing at elevated pressures into sandpacks containing various oil saturations. Normalized pressure gradient, and apparent viscosity are the indicators of foam stability and effectiveness for improving oil recovery.\u0000 The extent to which nanoparticles are covered with surfactant governs the foam stability both in static and dynamic conditions. Static foam is stable in the presence of oil only if the nanoparticles are partially covered by the surfactant. In the dynamic test, foam stabilized with the only surfactant collapses in the porous media when oil is present. Nanoparticles alone could not generate foam regardless of the presence of oil, but foam stabilized with nanoparticles partially covered by surfactant is stable in the presence of both residual and initial oil. In both static and dynamic conditions, nanoparticles completely covered with a bilayer of surfactant do not stabilize foam in the presence of oil. Partially covered nanoparticles foam also demonstrated salt tolerance in both static and dynamic test. Thus at appropriate surface coverage, the combination of nanoparticles and surfactant is more effective than either stabilizer alone.\u0000 The result shows that surfactant and nanoparticles interaction is important in foam stability in the porous media with oil. In particular, this interaction is synergistic at certain coverage. This type of synergy can provide much more robust mobility control for EOR processes involving gas injection.","PeriodicalId":425264,"journal":{"name":"Day 2 Wed, April 24, 2019","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130236253","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}