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Petrochemicals
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214799, โNovel Janus Carbon Nanofluids From Waste Plastics as Sustainable Nanoagents for Enhanced Oil Recovery: Scaleup Synthesis and Performance Evaluation,โ by Wei Wang, Sehoon Chang, SPE, and Ayrat Gizzatov, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper describes nanomaterialsโJanus carbon nanofluidsโderived from waste plastics and demonstrates the potential of the nanofluids as highly effective alternative nanoagents for enhanced oil recovery (EOR) applications at reservoir conditions. A novel, sustainable, cost-effective method has been developed to scale up synthesis of Janus carbon nanoparticles (JC-NPs) from waste plastic feedstock by combined pyrolysis, chemical functionalization, and pulverization, which allows for production of the JC-NPs in mass quantities at an industrial scale. Introduction Recent research has demonstrated that nanoparticles with asymmetric surface properties (i.e., Janus nanoparticles) could achieve a much higher efficiency of oil recovery factors with very low concentrations of loading compared with homogeneous nanoparticle fluids. To date, however, major challenges facing the exploration and use of Janus nanoparticles exist, impeding scalability of synthesis, tailored chemical functionalization, and the ability to introduce a diverse set of functionalities. Therefore, new methods for production of Janus nanomaterials on an industrial scale are desired. The authors present a novel technique to convert waste plastic materials into carbon-based nanomaterials for EOR applications. Waste plastics, as a low-cost feedstock, can be converted into high-value-added carbon-based microparticles through the controlled carbonization of polymers. Furthermore, the carbon microparticles (C-MPs) can be surface-functionalized by post-chemical treatment and then their chemical symmetry reduced to nanosize by a ball-milling technique. The resulting asymmetrically surface-functionalized carbon nanoparticles (i.e., Janus C-NPs) exhibit both nanoparticulate and surfactant-like properties that can be used as new nanoagents in nanofluid flooding for EOR applications. Experimental materials and measurement methodology are detailed in the complete paper. Results and Discussion Synthesis of C-MPs From Waste Polymers. Approximately 90% of the plastics produced globally consist of six types: low-density polyethylene, high-density polyethylene, polypropylene, polyvinylchloride, polystyrene, and polyethylene terephthalate (PET). Given their widespread use, these waste polymers constitute a substantial proportion of global plastic waste. Therefore, they present an opportunity to be used as precursors in the synthesis of C-MPs. This study offers an approach for repurposing these ubiquitous waste polymers. As depicted in Fig. 1, the authors propose synthesis of C-MPs through carbonization reactions using these waste polymers as feedstock. This methodology offers dual benefits. First, it presents a practical solution to the growing environmental concern posed by plastic waste. Second, it provides a cost-effective way to produce C-MPs, an essential component in many technological applications.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.55)
Novel Structural Aspects of Heavy-Crude-Derived Asphaltene Molecules for Investigating the Crude Mix Processability in Refinery Operation
Das, Raj K. (Corporate R&D Centre, Bharat Petroleum Corporation Ltd.) | Voolapalli, Ravi K. (Corporate R&D Centre, Bharat Petroleum Corporation Ltd.) | Upadhyayula, Sreedevi (Department of Chemical Engineering, Indian Institute of Technology-Delhi (Corresponding author)) | Kumar, Rajeev (Corporate R&D Centre, Bharat Petroleum Corporation Ltd. (Corresponding author))
Summary In this paper, we investigate the role of asphaltenes derived from heavy crudes, which dictates the behavior of crude mix properties for hassle-free downstream refinery operation. Combined characterization techniques such as proton nuclear magnetic resonance (H-NMR), cross-polarization magic-angle-spinning carbon-13 (CP/MAS C)-NMR, heteronuclear single-quantum coherence (HSQC), Fourier transform infrared (FTIR), thermogravimetric analysis (TGA), and X-ray diffraction (XRD) are used for the detailted study of Ratwai and Ras Gharib (RG)-derived asphaltenes to validate their structural role in selecting the optimal crude mix. As per our investigation, when the polyaromatic core of asphaltene structures are less substituted, the availability of aromatic hydrogen is more; it exhibits a stable crude mix as compared to heavy crudes that have more aromatic core substitution, despite the crudes possessing similar asphaltene content and physicochemical properties. This finding is further extended to West Canadian (WC) and Belayim (BL) heavy crudes for operational suitability. In this study, the key feature is to develop a CP/MAS C-NMR-based robust and quick characterization technique that could potentially become a prescreening method to assess crude oil compatibility and its various blend processability in the refinery system. Other characterization techniques, such as H-NMR, HSQC, FTIR, TGA, and XRD, would corroborate and confirm the reliability of the data obtained by CP/MAS C-NMR.
- North America > United States (0.95)
- Africa > Middle East > Algeria (0.28)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Oued Mya Basin > Hassi Messaoud Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Berkine Basin (Trias/Ghadames Basin) > Hassi Messaoud Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
As can be seen in Table 7 and Figure 1d, VT 4 shows a good prediction in density for heavy hydrocarbons by treating the heavy oil as one PC and six PCs, respectively, with six PCs having the optimized results. Figure 1d shows Cases 52 through 59 calculated with ฮฑ Functions 1 through 8 and VT 4 result in AARDs of 7.70%, 7.65%, 7.61%, 4.38%, 3.04%, 2.62%, 1.67%, and 1.91%, respectively. It can be observed that VT 4 results in predicting more accurate densities using ฮฑ Functions 1 (Case 52) and 3 (Case 54) compared to VTs 1 through 3; however, Cases 57 through 59 lead to a smaller deviation, with Case 58 (i.e., ฮฑ Function 7) having an AARD of 1.67%, which can be compared to that of 1.31% using the IM-E method (Chen and Yang 2020). More specifically, all these VT strategies increase the accuracy of the molar volume of liquid in predicting the densities of gas(es)- heavy oil/bitumen systems. Also, it is important to note that these VT strategies do not affect the saturation pressure calculation when predicting the density of heavy hydrocarbon mixtures (Whitson and Brulรฉ 2000; Li et al. 2013b). It is observed that VTs 1, 3, and 4 accurately predict the densities of heavy hydrocarbon mixtures, among which VT 3 results in the most accurate prediction for the PR EOS (i.e., ฮฑ Function 7). This finding is consistent with that presented elsewhere (Chen and Yang 2017).
Effect of Molecular Structure of Thio-Chemicals on Corrosion Inhibition in CO2 Corrosive Environments
Yang, Jiang (Northeast Petroleum University) | Wang, Xintong (China University of Petroleum (East China) (Corresponding author)) | Wang, Yefei (China University of Petroleum (East China)) | Yang, Zhen (China University of Petroleum (East China))
Summary Carbon dioxide (CO2) is frequently present in oil and gas fields, and its use in CO2 flooding for enhanced oil recovery is growing. However, CO2 is highly corrosive to steel in oilfield fluid. The effective and economical method for controlling corrosion is the addition of corrosion inhibitors for carbon steel materials. Thio-compounds of small size have shown potential as corrosion inhibitors to enhance the performance of imidazoline inhibitors. In this study, several small thio-derivatives inhibitors including mercaptoethanol (ME), thiourea (TU), mercaptoacetic acid (TGA), and 2-mercaptobenzimidazole (MBI) were compared to inhibit the CO2 corrosion. They were used as synergists to enhance corrosion inhibition of oleic imidazoline (OIM) on carbon steel in CO2-saturated brine at 60ยฐC. The corrosion inhibition was evaluated using weight loss and electrochemical techniques, while the surface was characterized using atomic force microscopy (AFM). Additionally, quantum chemical calculations were conducted to investigate the mechanism of corrosion inhibition. The results demonstrate that the MBI, with its aromatic group, exhibited superior corrosion inhibition performance compared with ME, TGA, and TU. The surface characterization revealed no pitting and localized corrosion at 10 ppm of inhibitor. A proposed interaction model suggests that OIM becomes protonated and forms a coadsorption layer with MBI on the carbon steel surface through electrostatic attraction. MBI adsorbs onto iron through a bidentate binding-N-S-bridge connection, effectively preventing carbon steel corrosion in the CO2 environments. This research contributes to establishing a structure-properties relationship for thio-chemicals, aiding in the development of more efficient corrosion inhibitors.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.66)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.98)
Department of Petroleum Engineering, Texas A&M University Summary Nonionic surfactants have proven successful and cost-effective in enhancing production from conventional and unconventional reservoirs. However, studies into the mechanism and performance of nonionic surfactants have been limited to reservoirs with temperatures below 200 F due to the temperature-dependent physiochemical properties, especially cloudpoint (CP). In this study, nonionic-ionic surfactant blends were designed to create nonionic systems with cloudpoint temperatures (CPTs) above 300 F for wettability alteration in high-temperature reservoirs like the Eagle Ford Shale in Texas, USA. Through CP, wettability, interfacial tension (IFT), and spontaneous imbibition experiments, 22 commercial surfactant samples (individual and blends) were investigated. Results showed that the amount of ionic cosurfactant affected thermal stability, with increasing concentration leading to increasing CPT. Wettability alteration was dependent not only on temperature but also on the class of ionic cosurfactant. Cationic cosurfactants were superior at improving nonionic surfactants' thermal stability. However, they resulted in oil-wet contact angles (CAs) with increasing temperature. On the other hand, anionic cosurfactants displayed better synergy in terms of wettability alteration, creating strongly water-wet and intermediate-wet CAs at high temperatures. Therefore, the focus was placed on nonionicanionic surfactant blends for the reservoir samples used in this study. Stable surfactant blends with CPTs from 316 F to 348 F were successfully created for enhanced oil recovery (EOR) applications at high-temperature conditions. Spontaneous imbibition studies using these blends indicated improved recovery by up to 173%. This work validates and builds upon previous studies of surfactant performance, wettability alteration, and IFT while providing new insight into nonionic surfactant blends at temperature conditions not currently available in the literature. It also serves as a template for the surfactant screening and selection process when considering nonionic surfactants.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.34)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.93)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (0.67)
- (2 more...)
Corrosion Inhibition of Benzyl Quinoline Chloride Derivative-Based Formulation for Acidizing Process
Yang, Zhen (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Wang, Yefei (Shandong Key Laboratory of Oilfield Chemistry, School of Petroleum Engineering, China University of Petroleum (East China)) | Yang, Jiang (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Wang, Jing (Shandong Key Laboratory of Oilfield Chemistry, School of Petroleum Engineering, China University of Petroleum (East China) (Corresponding author)) | Finลกgar, Matjaลพ (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China))
Summary Due to the severe and rapid corrosion of metallic equipment by strong acids at high temperatures, a high concentration of acidizing corrosion inhibitors (ACIs) is required during acidizing processes. There is always a need to develop more effective and environmentally friendly ACIs than current products. In this work, a highly effective ACI obtained from a novel main component and its synergistic effect with paraformaldehyde (PFA) and potassium iodide (KI) is presented. The ACI was prepared from the crude product of benzyl quinolinium chloride derivative (BQD) synthesized from benzyl chloride and quinoline in a simple way. The new ACI formulation, named โsynergistic indolizine derivative mixtureโ (SIDM), which consists of BQD, PFA, and KI, showed superior corrosion inhibition effectiveness (IE) and temperature stability compared with commercially available ACI. More importantly, the SIDM formulation eliminates the need for commonly used highly toxic synergists (e.g., propargyl alcohol and As2O3). In a 20 wt% hydrochloric acid (HCl) solution, the addition of 0.5 wt% SIDM mitigates the corrosion rate of N80 steel down to less than 0.00564 lbmยทft at 194ยฐF, while the corrosion rate at 320 ยฐF is 0.0546 lbmยทftยทwhen 4.0 wt% SIDM is added.
- Europe (0.68)
- North America > United States > Texas (0.47)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Acidizing (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 Solvent extracts obtained from center-cut horizontal core plugs selected in the Upper Wolfcamp (UW) and Eagle Ford source-rock (SR) beds contain unaltered volatile (i.e.,ย gasoline range) hydrocarbon (HC) compounds because they are extracted in a closed vial. Therefore, a C7 source parameter, a C7 maturity parameter, and pristane/phytane ratios are used to compare the source and thermal maturity of these petroleum and oil samples produced from nearby wells landed in the same SR reservoirs. Five distinct pay zones previously identified in the UW SR reservoir using geologic criteria each contain slightly different kinds of petroleum generated at different levels of thermal maturity. A thick overlying carbonate reservoir contains the kind of petroleum generated by the kerogen present in one underlying SR pay zone. The same source and maturity parameters demonstrate that the oil-prone kerogen present in the Eagle Ford SR beds in core plugs selected from wells located โ7.5ย mi (12ย km) apart on the San Marcos Arch in South Texas formed in different depositional environments. It is difficult to allocate commingled oil samples using only core-plug extracts because solvents extract the producible oil plus a component that does not readily flow from SR reservoirs because it is sorbed in kerogen and/or on clay minerals. However, because only saturate HC compounds are used to determine the C7 source and maturity parameters, they provide valuable insights about the nature of the free oil present in SR reservoirs and commingled oil samples.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.69)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Buda Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (40 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
Abstract An acid stimulation was performed in an ultra-deepwater pre-salt Brazil well to improve its productivity. The formation of hydrate plugs was a critical concern, as the stimulation requires water injection to neutralize the acid, and this well has a high GOR. Even with a risk of hydrate formation, acid stimulation is proven to be effective in recovering the production potential. However, experience with gas wells is still in the learning process with low best practices reported in the literature. The intention of this paper is to present a case history and the lessons learned during an acid stimulation in a high GOR well, in which the gas production was greater than anticipated leading to the formation of a massive hydrate plug, noted while the coiled tubing was being pulled and became stuck. The hydrate risk analysis and the steps taken to release the coiled tubing will be presented, and the discussion will include the following: Hydrate risk analysis from the acid stimulation program: as the subsea valves remain locked open during the rig operation, gas continuously migrates from the reservoir into the well leading to a high risk of hydrate formation during the water injection steps, requiring a bullhead with base oil to mitigate this risk. Also, a detailed evaluation of the risk of hydrate formation during the well startup will be discussed, as the high volume of water injected to neutralize the acid requires artificial lift to produce this effluent, in the case the only option was gas lift, the combination of high BSW% effluent and gas lift leads to a high risk of hydrate formation. Troubleshooting to dissociate the hydrate: After the hydrate identification some attempts to dissociate were taken, the effective one being a gas flush from the FPSO to the Rig, injecting gas to the well through the service line to lift the drilling fluid from the work over riser to the Rig, therefore reducing the pressure until being outside of the hydrate stable zone, making possible to pull the coil tubing in an inhibited liquid environment, in the case MEG 50%, to avoid hydrate reassociation. The figure below illustrates the steps of hydrate risk assessment during well startup: i) above 10% BSW the fluid temperature puts the subsea system inside the hydrate formation zone; ii) the evaluation of the best suitable thermodynamic hydrate inhibitor available to avoid hydrate reassociation and to move the system to outside the hydrate formation zone; iii) the gas flush to move outside of the stable hydrate formation zone at sea level depth, showing that the option was valid to dissociate a hydrate formed at this depth. This case history discusses an acid stimulation in a high GOR well, in ultra-deep water, offshore Brazil. The lessons learned in this operation will be discussed to propose a structured guideline for hydrate mitigation during acid stimulation jobs in high GOR wells, from the risk analysis before the operation until the well restart, including hydrate dissociation options.
Experimental Study of Creep Behavior at High Temperature in Different HMPE Fibers Used for Offshore Mooring
da Cruz, D. M. (Tecnofibers Desenvolvimento e Tecnologia Ltda, Itajaรญ, Santa Catarina, Brasil) | Barreto, M. A. (Tecnofibers Desenvolvimento e Tecnologia Ltda, Itajaรญ, Santa Catarina, Brasil) | Zangalli, L. B. (Tecnofibers Desenvolvimento e Tecnologia Ltda, Itajaรญ, Santa Catarina, Brasil) | Jรบnior, T. L. Popiolek (Policab Stress Analysis Laboratory, Federal University of Rio Grande, Rio Grande, Rio Grande do Sul, Brasil) | Guilherme, C. E. M. (Policab Stress Analysis Laboratory, Federal University of Rio Grande, Rio Grande, Rio Grande do Sul, Brasil)
Abstract Offshore moorings have been extensively researched in recent decades, and since the introduction of Taut-Leg systems made with synthetic polyester fibers as an alternative to steel catenaries, several fibers have gained significant prominence. High modulus polyethylene (HMPE) stands out due to its superior mechanical resistance and linear tenacity compared to many other fibers. However, it shows challenging behavior in creep, showing high strain rates and low creep resistance. Consequently, manufacturers have focused on developing HMPE fibers typified as "Low Creep," aiming to achieve satisfactory creep behavior and enable offshore mooring systems made entirely of HMPE. Such advancements could lead to the use of HMPE in offshore installations in ultra-deep waters, given its low elongation. The goal of this study is to evaluate the creep behavior of 6 HMPE fibers, including both European and Asian manufactures, with 3 fibers designated as "Low Creep." The evaluation encompasses different load temperature conditions. The experimental approach uses HMPE multifilaments, which serve as the base material for making mooring ropes. The results are compiled in tables, providing initial characterization results and average creep results, including creep strain rates. Creep graphs are drawn to facilitate understanding and comparison of the behaviors, along with a generalized statistical modeling of the creep-rupture surface for each fiber. The results show that the fibers designated as "Low Creep" indeed exhibit significantly better behavior than others, with lower strain rates. Among them, Fibers A and D emerge as the most promising for offshore mooring, showing greater resistance to creep. From a commercial standpoint, Fiber D offers the lowest cost per kg and presents favorable constitutive behaviors in specific operational contexts, as well as better stability with increasing temperature. In terms of future directions, other methodologies linked to the acquired experimental database should be explored, including analytical models and numerical simulations. Additionally, an investigation into sub-ropes and a detailed study of thermal degradation decoupling in the studied phenomenon should be considered for further research.
- South America > Brazil (1.00)
- North America (0.93)
- Research Report > New Finding (0.84)
- Research Report > Experimental Study (0.70)
Abstract Assessing the Viability of a Compact CO2-capture Technology for Offshore Installations: Design, Development, and Pilot Scale Demonstration The purpose of the R&D project discussed in this paper is to assess the potential of a novel compact CO2-capture technology. The technology is founded on decades of experience in analogous processes, employing static mixing and separation. Flue gas or process streams containing CO2 is mixed with a solvent, in one or more stages. Effective co-current mixing of the phases is crucial to the technology's efficiency and a vital part of ensuring the technology's lightweight and compact advantage. The objective is accomplished via three significant steps, which include designing and constructing a complete pilot-scale unit, conducting experimental tests for two months, and developing a process model that explains the physical findings. The results from this study will be presented in this paper. The project is funded by CLIMIT-Demo and aligns with climate objectives by addressing the urgent need to mitigate greenhouse gas emissions in the energy sector and aims to develop a novel, compact amine-based CO2 capture technology that can be applied in various settings, including onshore and offshore oil and gas installations for both flue gas, blue hydrogen, and other industrial process streams. The main goal at this stage is to verify the technology's absorption efficiency and assess its energy efficiency and viability. The development of lightweight and compact CO2-capture technology is especially critical in offshore oil and gas operations, where weight and space limitations present significant challenges. The pilot system encompasses the compact absorption module, desorption module, heat exchangers, pumps, control valves, and a control system. Additionally, this system is equipped with sensors and customization capabilities to assess CO2 concentrations in various locations, measure heat generated by the reaction between amine and CO2 and perform sensitivity analysis with respect to the orientation of mixers and residence time. The results will facilitate better understanding of both physics and chemistry of solvent-based CO2 capture. A comprehensive test matrix has been developed that will enable better understanding of the dynamic variations that occur during the treatment of process streams. This test matrix includes testing different pressures and concentrations of CO2, solvent and flue gas flowrate and solvent temperature to measure a variety of factors, including pressure drop measurements across the system, CO2 mass transfer efficiency, CO2 capture efficiency, and energy usage. Further, this data is used to create a process model that allows for the development of a predictive framework. This framework is then used to optimize the process parameters to achieve maximum performance and design considerations for scale up. This work is essential for advancing our understanding of Compact CO2-capture and mitigating our impact on the environment by commercializing CO2 capture for offshore installations.
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)