Day 2 Wed, March 27, 2019最新文献

{"title":"Managed Pressure Drilling Saves Multimillion Dollar Well from Abandonment; Enabled Operator to Drill and Isolate Section to Target Depth in a Challenging Plastic Salt Formation","authors":"Qasim Ashraf, A. Khalid, Khurram Luqman, Ayoub Hadj-moussa, Muhammad Shafique, Khurram Abbas, Muhammad Tashfeen, Shahjahan Khan, Rizwan Jameel","doi":"10.2523/IPTC-19438-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19438-MS","url":null,"abstract":"\u0000 The Northern Potwar Plateau of Pakistan is known for its severe geological features. Many wells have been drilled in the region, but geological correlations in neighboring fields have proven to be challenging. Excessive tectonic activity and faults have resulted in formation repetitions, abnormal in-situ stresses, and variable formation pore and fracture pressures.\u0000 One such field in the region is MDK field, where the operator was in the process of drilling a second well. Drilling of the 8 ½-in. hole section was in progress at 11,004 ft. (3,354 m) when the Bahadur Khel Salt formation was encountered. Upon drilling further into the formation, the operator encountered severe hole stability issues coupled with lost circulation. While in the salt formation, whenever circulation was stopped and annular pressure losses were eliminated, the drill string would become stuck. Upon resuming circulation, the pumping pressure would rise abruptly. The formation was highly stressed and was exhibiting a creeping behavior. Any reduction in the bottom hole pressure (BHP) would cause the formation to creep into the wellbore.\u0000 The operator spent a month attempting to drill through the highly stressed plastic salt formation, without success. The oil-based mud system was already weighted up to its maximum, and no other conventional means existed of controlling the creeping salt. The operating company had already spent ~USD 19 million dollars on the well, and was considering abandoning it after a nearby well in the same formation had been abandoned despite four unsuccessful sidetracks.\u0000 Maintaining a constant bottom hole pressure (CBHP) across the formation at all times was the only way to stabilize the salt formation and lost circulation treatment. Only managed pressure drilling (MPD) could achieve the application of CBHP. An MPD system would enable the operator to compensate for the lack of BHP by applying surface backpressure, thereby maintaining the target pressure across the formation at all times. With the help of the MPD system, the operator also sought to calculate the formation creep rate, so as to evaluate a time window for running in and out of the hole.\u0000 Besides drilling, the operator also intended to isolate the challenging section with a liner. With proper planning, the MPD system could help to achieve this objective.\u0000 A full MPD system was deployed to the wellsite and drilling resumed with a CBHP in dynamic and static periods. By CBHP MPD, the operator was able to tag bottom. Drilling and underreaming of the 8 ½-in. hole section resumed and continued until reaching the target depth of 14,745 ft. (4,494 m). After drilling, the 7-in. liner was set and cemented to the target depth using MPD.\u0000 Applying CBHP MPD enabled the operator to drill through 3,832 ft. (1,168 m) of the hole section and save the well from abandonment. This paper studies the design, execution, and lessons learned when applying MPD on the subject well.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121820569","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":"Cohesive Approach for High-Resolution Seismic Using Inversion & Imaging in Malaysian Carbonate Field","authors":"Y. Bashir, A. Babasafari, A. Biswas, R. Hamidi, Seyed Yaser Moussavi Alashloo, Hammad Tariq Janjuah, D. Ghosh, C. Sum","doi":"10.2523/IPTC-19266-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19266-MS","url":null,"abstract":"A majority of remaining proven Oil & Gas reserves is contained by Carbonate reservoir, and much more complicated to explore as imaging of the Carbonate rocks is poor. In case of Carbonate data, seismic diffraction imaging has contributed to an enhancement in the quality of seismic but there is still lack of understanding the lithology and impedance contrast which can be defined by the seismic inversion. In contrast, to the conventional process, an integration of seismic inversion methods are necessary to understand the lithology and include the full band of frequency in our initial model to incorporate and detail study about the basin for prospect evaluation. In this paper, an integrated approch is developed for better deleniation of subsurface structure and lithologies. Seismic post stack inversion technique is applied to the Carbonate field to study Electroficies and lithofacies of subsurface strata for better and detail study of the reservoir.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"88 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125964250","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":"Numerical Study on Proppant Transport and Placement in Complex Fractures System of Shale Formation Using Eulerian Multiphase Model Approach","authors":"Ruoyu Yang, Jianchun Guo, Tao Zhang, Xudong Zhang, Jian Ma, Li Yang","doi":"10.2523/IPTC-19090-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19090-MS","url":null,"abstract":"\u0000 Slick-water fracturing treatment is one of the most effective method to develop shale reservoir, which creates complex fracture system by connecting the pre-existing natural fractures. However, the proppant transport and placement behavior is quite different from that in conventional bi-wing fractures due to the low viscosity fluid system and intersections between fractures. The goal of this work is to simulate and understand the characteristic of proppant transport behavior in Complex Fractures network.\u0000 A Eulerian multiphase model is introduced to simulate the transport and settling behavior in the hydraulic fracture network, which takes turbulence effects and friction stress between the proppant particles into consideration and fully couple the fluid phase with particle phase. Simulation work was conducted to investigate the control mechanism and influencing factors for proppant transportation from main fracture into secondary and tertiary fractures.\u0000 The simulation results indicate that a small proppant dune quickly forms in the main fractures first, and almost no proppant enters the lower grade fracture until the proppant dune in the intersection reaches a specific height. With continuous injection of slurry fluid, majority of the proppant enters in the lower grade fracture which is controlled by gravity rolling from the dune in main fractures and fluid drag force, and the proppant settles quickly and gradually reach their own equilibrium height. Parametric study shows that smaller proppant density and particle size can also help proppant transport into secondary fractures and form a higher equilibrium height dune, resulting in larger effective propped area. Moreover, when the lower grade fracture is closer to the inlet entrance, the proppant is more likely to transport in, and the height of sand dunes formed in the fractures is higher.\u0000 The proppant transport process in complex fracture systems is simulated by Eulerian Multiphase Model in this paper. This study extends the understanding of the process and mechanism of proppant transport in complex fracture system and controlling factors, which helps optimize hydraulic fracturing design in shale formation.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"174 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123257725","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":"Modeling and Experiments for CO2 Blowdown from the Cryogenic Pilot Plant and the Mitigations Measure","authors":"Amiza Surmi","doi":"10.2523/IPTC-19114-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19114-MS","url":null,"abstract":"\u0000 A pilot of cryogenic distillation technology is designed and installed for separation of the high CO2 concentration of feed up to 80 mol % from natural gas. However, the main concern was the dry ice formation during depressurization or blowdown might cause the pipeline and equipment blockage and consequently resulting in safety issues.\u0000 A dynamics simulation and modeling were conducted using commercialize software to determine the settle out temperature during the blowdown especially emergency condition. The investigations were focused on the high operating pressure and low operating temperature with a high CO2 composition which is closer to transient condition and solid region. Then, more comprehensive modeling was conducted by incorporating the equipment and piping design data including the sizing of relieve valves (RVs) and blowdown valves (BDVs). The accuracy of information is very crucial to obtain more reliable results.\u0000 It was observed that at high operating pressure, (50 to 75 barg) and low operating temperature,(-58 to 15 °C) the settle out temperature due Joule-Thomson (JT) effect were −58 °C and −92 °C for 60% and 80% CO2 concentration, respectively. Based on the phase diagram, in this condition, the CO2 will be under a solid region. As a result, the Minimum Design Metal Temperature (MDMT) of −100 °C was selected for equipment and pipelines design to avoid material brittle-fracture. Few mitigations measure were designed and installed to avoid the CO2 solidification. The BDVs were installed at the warmer area to minimize the JT effect leading to lower operating temperature than CO2 solidification temperature resulting to potential equipment blockage. The electrical heat tracings were installed at the outlet flange and outlet line of RVs and BDVs to maintain fluid temperature above CO2 solidification limit. This is to prevent CO2 solid from attaching to the pipe wall and build up in the piping in the event of relief. Another mitigation was by installing the outlet line with sloped toward vent header and free from instrument probe or sensor to prevent CO2 solid from build up at piping dead leg section. As a result, no sign of CO2 solid found in the sections that equipped with mitigations measure during experiments.\u0000 An inherently safer design of equipment and pipelines are very crucial especially for high CO2 concentration, high operating pressure and low operating temperature with the appropriate mitigations to avoid catastrophic failure.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"42 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116444807","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":"Separate Molecular Weight and Pressure Injection Technology for ASP Flooding in Daqing Oilfield","authors":"Gao Guanglei, Zhou Wanfu, Wu Junzheng, Zhu Shaogong, Bin Huang, Xu Dekui, Cai Meng, Liu Chongjiang, Song Xingliang, Li Haicheng, Li Kuilong","doi":"10.2523/IPTC-19529-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19529-MS","url":null,"abstract":"\u0000 The displacement target of the ASP flooding in Daqing Oilfield has gradually shifted to class II reservoirs, which are characterized by multiple layers and great difference in permeabilities. The percentage of 3-5 layer injection wells has reached more than 50%. Currently, there are two main problems existing with the separate injection technology. First, due to the different microscopic molecular structure of the ASP solution, the viscosity loss of the ASP solution is more than 1 times higher than that of the polymer under the same injection conditions, which affects the displacement effect of ASP flooding. Second, the ASP system of a single molecular weight cannot meet the displacement requirements of all oil layers. To solve the two problems, a separate molecular weight and pressure injection technology is developed for ASP flooding. Based on the microscopic mechanism and simulation study, the separate molecular weight and pressure injection technology for ASP flooding is developed in this paper. The injection string can inject different ASP solutions of different molecular weights into different layers at different injection rates as required to match different oil layer permeabilities. Thus, the control of molecular weight and injection rate for separate layers in ASP flooding can be achieved. At the flow rate of 50m3/d, the adjustment range of molecular weight is 20-50%, the maximum throttling pressure difference can reach 1.5MPa or more, and the maximum loss of viscosity is less than 7.8%. Up to now, this technology has been applied to the field tests of more than 800 wells. Since the application of this technology, the injection profile has been effectively improved, and the pay-gross thickness ratio has been increased by 8%. With this technology, the separate injection for 3-5 layers and control of molecular weight as well as injection rate for separate layers to match the different oil layer permeabilities in ASP flooding can be achieved. This technology will play an important role in the development of major oil fields in the future.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122736887","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":"Effect of Pore Pressure Depletion on Wellbore Stability and Hydraulic Fracturing in Sandstone Reservoir","authors":"M. Al-Dossary, O. Hamid, S. Elkatatny","doi":"10.2523/IPTC-19097-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19097-MS","url":null,"abstract":"\u0000 Development of stress sensitive reservoirs, especially in challenging environment, is raising awareness that geomechanics is a vital aspect of reservoir management. Understanding reservoir geomechanical behavior becomes more and more important for petroleum industry. A significant changes in formation pressure caused by depletion will induce deformation and stress/strain changes in the reservoir and the surrounding formation, understanding in-situ stresses and how stress changes in and around the reservoir due to depletion is important in a multidisciplinary approach to reservoir characterization and management.\u0000 These changes in stresses/strain affect the reservoir as well as the overburden and underburden formation, which directly affect drilling and stimulation operations strategies. Reservoir compaction, shear casing and well damage, cap-rock integrity, fault reactivation and sand production can occur during reservoir depletion.\u0000 To address these issues, 3D geomechanical models have been developed (which describe the state of stresses in the reservoir and overburden). 4D geomechanics models (dynamic models, that describe the changes in stress over time with production are required.\u0000 Reservoir Geomechanics approaches, this paper address and answer the following questions:\u0000 How Geomechanics changes in stresses and strain impact wellbore stability related issues and stimulation operations?\u0000 Stress rotation around faulted zones.\u0000 How depletion effect hydraulic fracture growth?","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122999959","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":"Identification and Analogy of Carbonate Geometries Between Offshore Indus Basin in Pakistan and Proven Carbonate Play","authors":"Muhammad Hanif Khan, T. Maqsood, T. Jaswal, M. Mujahid, M. S. Malik, E. Jadoon, Uray Lukman Hakeem","doi":"10.2523/IPTC-19302-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19302-MS","url":null,"abstract":"\u0000 This article investigates the seismic reflection geometries (possible reservoir) of Paleogene of Offshore Indus Basin Pakistan (shelf area) from 2D seismic and make an analogue with the proven carbonate reservoir geometries found in countries such as Canada and Middle East.\u0000 The 2D seismic data are used to interpret the possible carbonate features and methods to identify them and define its depositional setting on the carbonate platform.\u0000 The offshore Indus Basin is tectonically a rift and a passive continental margin basin, located in Offshore Pakistan and Northwest India where carbonates were deposited on the shelf and the deep offshore area during early post-rift phase. In the deep offshore area, carbonates were set on volcanic seamounts during the Paleogene age.\u0000 In Paleogene, the Indian Plate was passing through the equator in the conditions of warmer water with appropriate water salinity, where those conditions were suitable for the growth of organisms responsible to develop reefs in the Offshore Indus area. The available seismic data analysis has indicated the possible presence of different carbonate reefs on the shelf. The seismic data enabled to define the possible carbonate Rimmed shelf depositional model in the area.\u0000 The aim of this article is to highlight and analogue carbonate seismic geometries, their internal architecture in the Paleogene interval of the Offshore Indus Basin (shelf area) and how to identify them, which may help for further exploration in Offshore Indus Basin.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129805952","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 Risk-Effectiveness Design Method for Flare Height of Natural Gas Pipeline System","authors":"Xia Wu, Changjun Li, Wenlong Jia, JunCheng Mu","doi":"10.2523/IPTC-19246-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19246-MS","url":null,"abstract":"\u0000 The objective of this research is to develop a risk-effectiveness design method for flare height of natural gas pipeline system. The advantage of the proposed design method over the traditional methods is the impacts of population density to flare risk are considered and more economic flare height could be obtained under lower risk levels. The conventional design methods obtain the same flare height for both high and low population density area. A risk-effectiveness model is established by combing the risk cost and the flare construction cost. The optimal flare height is the minimum value calculated by the first derivative of the model. An application is given to show the model's usability under different population densities. The flare height of 19.4m, 21.7 m, 24.3m, and 28.6m are obtained by the method for four different regions with the population densities of 5.2×10−5, 1×10−4, 3×10−4 and 7×10−4 person/m3. The increased flare height implies the increase of the risk levels accompanying with the increase of the population density. A comparison with the design results gained by the API RP 521 method is made to prove the effectiveness of the proposed method. Under the condition that the compensation per person is 40 times of the construction fees per meter, the flare heights get by the proposed method are 69.7%, 78.0%, 87.4% and 102.9% of the API design heights with the population densities of 5.2×10−5, 1×10−4, 3×10−4 and 7×10−4 person/m3. The results show that a lower flare height would be obtained by the proposed method with the population densities lower than 7×10−4 person/m3, and a direct construction saving could be gained under this circumstance, which proved the economy of the proposed method. The main novelty lies in the risk-effectiveness model which combines the loss of human injuries and the cost of flare construction to obtain the optimal design results for different regions. Compared with the traditional method, the proposed method can not only reflect the impact of the population density to flare risks, but is also more economical under certain circumstance. This makes it possible to gain more benefits for flare operators under low risk levels.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129825840","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":"Characteristics and Influence Factors of the Middle-Lower Jurassic Tight Sandstone Reservoirs in the Taibei Sag, Turpan-Hami Basin","authors":"X. Si, Yang Xu, Xin Wang, Huajun Guo, Yazhe Li, X. Shan","doi":"10.2523/IPTC-19069-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19069-MS","url":null,"abstract":"\u0000 Sandstone can be divided into many types with reference to permeability and porosity. Some scholars and researchers have established criteria to classify tight sandstone by using porosity and permeability. Sandstone with permeability less than 1mD and porosity less than 10% could be called tight sandstone. Exploration and development of tight sandstone gas has become a hot spot of oil and gas exploration (Dai J. et al., 2002) in China. Quite recently, tight sandstone gas reservoirs of different scales have been discovered in the middle-lower Jurassic of Taibei Sag in Turpan-Hami Basin. The purposes of this paperare to analyze the texture and composition of the middle-lower Jurassic tight sandstones, investigate diagenesis type and reveal the influence of diagenesis on reservoir quality.","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"82 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129684062","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":"Multiscale Water Ion Interactions at Interfaces for Enhanced Understanding of SmartWater Flooding in Carbonates","authors":"S. Ayirala, S. Saleh, S. Enezi, A. Yousef","doi":"10.2523/IPTC-19066-MS","DOIUrl":"https://doi.org/10.2523/IPTC-19066-MS","url":null,"abstract":"\u0000 In this study, we summarize and discuss the data reported from a series of multiscale experiments to explore the interactions of salinity and water ions at both fluid-fluid and rock-fluid interfaces to understand the pore scale mechanisms responsible for oil recovery in SmartWater flooding. These experimental data on various crude oil/brine/carbonate and crude oil-brine physicochemical changes/effects at elevated temperatures were obtained using a variety of static and dynamic techniques at different scales ranging from atomic-molecular-macroscopic scales. The techniques include surface force apparatus (SFA), cryo-broad ion beam scanning electron microscope (BIB-SEM), zeta potentials, microscope based oil liberation, interfacial shear rheology, and integrated thin film drainage apparatus (ITFDA). The salinities of brines were varied from zero salinity deionized (DI) water to higher salinity injection water in addition to changing the individual ion compositions.\u0000 The integration of results obtained from these different multiscale experiments showed that both salinity and individual water ions play a major role not only to determine the oil release from rock surface due to the interactions at rock-fluids interface, but also to impact released oil ganglion dynamics for efficient oil mobilization through the interactions at fluid-fluid interface. The key findings can be summarized as the following: (1) At zero salinity, unfavorably much higher adhesion as well as stronger rigid films to adversely impact crude oil droplets coalescence were observed at rock-fluids, and fluid-fluid interfaces, respectively; (2) An optimal lower salinity containing sufficient amount of sulfate ions is necessary to cause nano-scale ion exchange at the rock-fluids interface that changes the surface charge/potential to favorably alter adhesion and microscopic contact angles for efficient oil release from rock surface; (3) An adequate salinity containing higher amounts of magnesium and calcium ions is desired to form less rigid films at the fluid-fluid interface that promote the coalescence of released oil ganglia for effective mobilization. Based on these novel findings, SmartWater can be defined as a tailored water containing certain salinity and selective composition of three key ions including sulfates, magnesium, and calcium. It must contain lower amounts of monovalent ions and should have the right balance of the three key ions to enable favorable interactions at both fluid-fluid and rock-fluids interfaces and result in faster as well as higher oil recoveries in carbonates.\u0000 The analysis on multiscale water ion interactions at both the interfaces performed in this study also sheds the important learning point that not every low salinity water can become a SmartWater for carbonates. These new learnings and the novel knowledge gained would provide useful practical guidelines on how to design optimal injection water chemistries for SmartWater flooding projects in the f","PeriodicalId":105730,"journal":{"name":"Day 2 Wed, March 27, 2019","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123999857","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}