Day 3 Fri, March 03, 2023最新文献

{"title":"Extended Abstract: Complex Offshore Well Intervention Now Possible by using Thru-Tubing Bridge Plug to Produce By-Pass zone and Isolate Lower Production Zone","authors":"S. Eyuboglu, Erlangga Siregar, B. Andhika, Febrian Murvianto, Zandra Yuliarosa, Patria Siahaan","doi":"10.2523/iptc-22996-ea","DOIUrl":"https://doi.org/10.2523/iptc-22996-ea","url":null,"abstract":"\u0000 Isolating lower production zone (water shut-off) and finding new perforation intervals from another reservoir zone is a typical well intervention application in mature fields. In normal conditions, legacy permanent barriers (Through Tubing Bridge Plugs -TTBP) have been used in those applications very successfully. However, challenges are posed by, well bore restrictions (passing smaller OD restrictions), rig height, reliability and setting validations with legacy tools in harsh environments and well conditions. This paper discusses the challenges during offshore well intervention operation in Indonesia due to the limited space for rig-up, limited crane lifting capability, and un-manned well platform with only daylight operation and the solutions for these challenges with new slim-sized TTBP technology and the slim-sized Pulsed Neutron tool.\u0000 Critical success factors of this operation included providing valid gas saturation data by using a 1 11/16\" Pulsed Neutron tool (TMD3D) to determine the remaining gas in producing interval and any bypassed opportunities; establishing enough force by using a slim size electromechanical setting tool (DPU) to set the 1 11/16\" TTBP at the desired depth and establishing a mechanical barrier which can hold up to 1200 psi differential pressure until a cement cap can be established; and running a perforation simulation to select the right gun to create an effective perforation tunnel between the wellbore and the formation for optimized gas production from the bypass zone.\u0000 Despite all the challenges, a good mechanical barrier was established to isolate the lower water production zone and successfully determine gas saturation in bypassed reservoirs by using the Pulsed Neutron data. Perforation intervals were selected with the pulsed neutron analysis. After perforation, significant gas production was established which was 50% higher than predicted. New slim-sized technology tools resulted in flawless job execution with their high reliability and cost-effective solutions without any service quality issues. In addition to increased gas production, efficient operation resulted by completing the job one week earlier than scheduled, which provided extra cost savings. This case study identified the challenges in complex well intervention operations and provides a valuable water shut off solution by using new 1 11/16\" TTBP and 1 11/16\" DPU technology. The solution has proven to provide tremendous cost saving for production enhancement activity.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"66 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130184601","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":"Resolving Uncertainty in Oil Quality and Extension of Field Producible Area Using Latest LWD NMR Technology","authors":"A. Al-Fawwaz, A. Usman, Mohammad M. Najem, A. Aboudi, F. Al-otaibi, Marie Van Steene, J. Dolan","doi":"10.2523/iptc-23054-ms","DOIUrl":"https://doi.org/10.2523/iptc-23054-ms","url":null,"abstract":"\u0000 This paper describes how the uncertainty in oil quality in an offshore carbonate reservoir was resolved using the latest slim logging-while-drilling (LWD) nuclear magnetic resonance (NMR) tool. This tool was included in the bottomhole assembly (BHA) during drilling of the sidetrack well with the objective of confirming the presence of immovable heavy-oil/tar mat below the light/heavy-oil contact (LHOC). However, the tool showed that the reality was different from the expectations as movable/light hydrocarbon was confirmed below LHOC thereby leading to an extension of the field producible area.\u0000 The NMR interpretation methodology followed two scenarios based on an offset well with a rich NMR dataset. In the first scenario, because of the absence of porosity deficit and low apparent bound fluid volume, no heavy oil was identified, and the tool provided permeability and irreducible water saturation. In the second scenario, heavy oil was identified primarily from the presence of high apparent bound fluid and secondarily by a porosity deficit, and oil viscosity was computed.\u0000 The high-angle well intersected the same carbonate reservoir layer multiple times. The NMR measurement showed that Zones A–1, A–3, and B contained light oil, while the expectation for Zone B was to contain a heavy oil layer below the LHOC. The NMR identified heavier oil in each crossing of Zone A–2. An oil viscosity gradient was observed on both crossings of the reservoir layers. The reservoir was otherwise at irreducible water saturation in the subsequent interceptions, and the heavy oil or tar were not identified again. All the observations from the tool were supported by related observations from the mud logging gases. The first application of this service in this field was a success. The NMR provided unique fluid typing information, confirming that most reservoir sections contained light oil and quantified the heavy oil viscosity variations along the reservoir layer, which could not be quantified from the density, neutron, or resistivity measurements.\u0000 Finally, the NMR measurement showed that the reality of heavy oil distribution in this part of the reservoir was quite different from what was expected (i.e. the presence of immobile heavy oil below the LHOC) based on the reservoir model, enabling the prospect of light oil production from this part of the reservoir.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"56 ","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120875276","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":"Algorithm for Real-Time Field-Data-Driven Automation for Intelligent ESP-Lifted Multilateral Wells","authors":"A. Sadowska, A. Meredith, Gordon Goh Kim Fah, Ehab Yassir, Agustín Gambaretto, Dileep Divakaran, Abdullah Almana","doi":"10.2523/iptc-22749-ea","DOIUrl":"https://doi.org/10.2523/iptc-22749-ea","url":null,"abstract":"\u0000 Multilateral wells with electric submersible pumps and intelligent completions are notoriously difficult to operate and require long testing and frequent retests due to production condition changes and significant transients resulting from the horizontal undulating drains. For human operators, this task is very time-consuming and extremely challenging given the multidimensional and multi timescale system characteristics. However, the process can be automated via optimisation and control, with the proposed algorithm responding to observed production and system changes throughout the well’s life. To that end, a reduced-order well model is derived and validated with real-well-matched synthetic model data, and subsequently an automation algorithm is developed. This innovative and integrated approach to real-time lift and inflow automated control offers the prospect of boosting operators’ production value and investment returns. The algorithm utilises existing or new intelligent completion hardware and instrumentation and the wellsite-deployable smart algorithm, capable of adjusting to varying well conditions and optimally managing the production throughout the well’s life. To achieve that, the algorithm allocates flow-rate and water cut contributions from each lateral or zone and as such recalibrates the well model on the fly using the real-time field data. We present simulation results using a field-data-matched synthetic model and are working with an operator to implement the technology in the field. All in all, such a data-driven automation to autopilot intelligent production is now within sight and could in the future scale towards multiwell/fieldwide solution.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133408727","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":"High Pressure 2×2 Screen Development for Extended-Reach, Open-Hole Shunted Gravel-Pack Wells","authors":"John S. Sladic, J. Brasseaux, Stephen Mcnamee, R. Hodge","doi":"10.2523/iptc-22995-ms","DOIUrl":"https://doi.org/10.2523/iptc-22995-ms","url":null,"abstract":"\u0000 The industry has a long history of Shunt Tube Technology (STT) used in Gravel Pack operations. The traditional 2x2 configuration of two transport tubes and two pack tubes for long horizontal openhole shunted gravel pack screens worked well for applications upto 1,000 meters, however in the age of extended reach offshore gravel pack wells, modifications to the existing system were required to deal with higher surface pumping pressures, higher screenout pressures, and increased sand placement requirements of the longer extended wells.\u0000 The new system was designed to provide the industry a minimum openhole shunted gravel pack length of 1,500 meters based on customer targets. The target design parameters for the high-pressure extended reach system were set at 7,000 psi operating pressure, 150,000 pounds of proppant and a minimum overall gravel-pack length of 1,500 meters.\u0000 To achieve this, the existing low-pressure system was evaluated through Computational Fluid Dynamics (CFD) analysis, actual pressure and erosion testing to determine ultimate limitations of the existing architecture. Upon the conclusion of baseline testing, a multi-facetted system improvement plan was developed to create a new system for high-pressure extended reach applications. Areas identified as leading elements for improvement in a long reach high-pressure system were the top rings which divert flow from the transport tubes into the pack tubes at each screen joint, nozzle placement on the pack tube, enhanced nozzle erosion resistance, and the jumper tube assembly with its connectors and seals. Additional improvements to the connector retention system, robust protective split cover, and improved connection dehydration screens would serve to improve run rate, increase RIH durability and improve gravel-pack quality across the non-permeable connection.\u0000 After design and qualification of individual pressure retaining components, all system elements were combined, and complete system testing was performed. The system performance testing centered on four test subjects. These were 4-point bend testing, multi-joint erosion testing, multi-joint gravel-pack testing, and rig makeup testing.\u0000 This paper will summarize the testing involved in individual component development, system qualification and results of the first field installation.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131453691","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":"Establishment of a Workflow to Assess Pore Collapse Mechanics During a Series of Loading and Unloading Using Micro-CT Scan and Rock Mechanics Testing","authors":"O. Hamid, H. Aljamaan, M. Altwaijri","doi":"10.2523/iptc-23002-ms","DOIUrl":"https://doi.org/10.2523/iptc-23002-ms","url":null,"abstract":"\u0000 Characterization of the reservoir rock elastic and plastic behavior is essential to set a series of guidelines for reservoir management, especially during gas storage cyclicity. The reservoir rock is subjected to loading during injection and unloading during depletion. These procedures lead to increases and decreases in the magnitude of the effective stresses in the poroelastic media. The guidelines for the reservoir development should be set to operate the field within the elastic limit of the formation to ensure the undamaged permeability of continuous fluid flow in and out of the reservoir.\u0000 Based on these factors, there is a need to accurately measure the dynamic permeability and porosity by characterizing the pore space and pore throat collapse for the current and future injection and depletion operations. This invention will achieve this measurement through a series of alternating measures between a three-dimensional (3D) X-ray computed tomography (CT) imaging and triaxial testing. These accurate and actual measurements mainly come from core plugs testing.\u0000 The process starts (T1) by scanning the core plugs with high-resolution imaging technology to map pore space and pore throat. The samples will be subjected to the first step of loading and unloading during Thick Wall Cylinder (TWC) test using different axial and confining pressure. The samples will be imaged and then mapped in the pore space and pore throat at a time (T2), and these processes will continue for ten cycles of loading and unloading. The results will be interpreted and extrapolated to match the number of injection and depletion scenarios. The fluid flow will be numerically simulated at the pore scale using direct flow modeling within the pore space with the Navier-Stokes-Brinkman equation to evaluate changes in permeability and porosity.\u0000 Using these novel integrated processes presented by this invention, injection and depletion guidelines will be set for future operations; this methodology also can be used for oil recovery to ensure safe operations within an elastic limit to avoid permeability damage that will lead to safe, effective, and economical operational scenarios.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123702673","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":"Pilot Installation of Ceramic Coated Through Tubing Sand Screen Installation in Gas Producer Offshore Malaysia","authors":"Sarah Nabilah Ibrahim Kamal, Zulkifli B M Zin, Nur Hazrina Kamarul Zaman, M. S. A Rahim, E. A. Rosland, Khiril Shahreza Salleh","doi":"10.2523/iptc-23020-ea","DOIUrl":"https://doi.org/10.2523/iptc-23020-ea","url":null,"abstract":"\u0000 Well X, a gas producer located in offshore Malaysia had to be beaned down and subsequently shut in due to sand issues after 7 years of production through pressure depletion. It was completed in cased and perforated completion without any sand exclusion and has been producing since 2014. The evaluation on the sand control solution for Well X prioritizes remedial downhole sand control that is able to withstand highly erosive environment due to its high fluid velocity. As such, a ceramic coated Through Tubing Sand Screen (TTSS) was installed in 2021 and successfully reactivated the well to produce with minimal sand.\u0000 A series of qualification testing was conducted during the technology evaluation to demonstrate the ceramic coated TTSS resistance towards erosion and corrosion i.e. Gas Screen Erosion Test (GSET), Corrosion Test and Mechanical Strength Test. Studies on erosional velocity, Particle Size Distribution (PSD) and production analysis were conducted to determine the wire wrapped screen slot size and ensuring the mixture velocity is within the screen operating envelope.\u0000 Upon installation, the well performance was monitored using Acoustic Sand Monitoring (ASM) sensor and Online Sand Sampler (OSS) during the initial flowback and continued using manual spot sampling at the multiphase flowmeter. The screen retrieval was planned after 4 months flowing period for evaluation and the same screen was reinstalled as it was in good condition and met the inspection criteria. The installation of the ceramic coated Through Tubing Sand Screen (TTSS) at Well X has successfully demonstrated its resistance against erosion with good production and sand control performance.\u0000 This paper will share on the overview of the ceramic coated TTSS including the analysis on screen design selection, screen retrieval findings and well performance post TTSS installation.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114220241","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":"Revitalizing Vintage 3D Land Seismic Dataset Using Advanced Signal Processing and Imaging Techniques: A Success Story from Onshore Central Thailand","authors":"Napat Wanpiyarat, R. Chakraborty, S. H. Ng, N. Phantawee","doi":"10.2523/iptc-22948-ea","DOIUrl":"https://doi.org/10.2523/iptc-22948-ea","url":null,"abstract":"\u0000 We present a case study on the application of modern signal processing and depth-imaging techniques to vintage land seismic data from the Phitsanulok Basin, onshore central Thailand, in which four overlapping 3D surveys were pre-migration merged and imaged to form a single volume. The legacy data processing was limited to the application of dip-filter-based noise attenuation, pre-stack time imaging and post-stack survey merging, which leads to unresolved geophysical challenges associated with each process. In this study, a cascaded application of surface-wave and coherent noise attenuation was followed by a surface-consistent deconvolution that is suitable for stabilizing the amplitude and phase response of the embedded wavelet. Then, we applied a 5D matching-pursuit Fourier interpolation technique for interpolation and regularization in the offset-vector tile domain of the sparsely and irregularly sampled data. Finally, anisotropic depth imaging was implemented to reduce structural uncertainty. Our results show that the modern processing workflow further enhances continuity and accuracy of structural images, overcoming the limitations imposed by the vintage acquisition parameters. As a result, these improvements will reduce the risks associated with future development plans.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"74 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114838103","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":"3D Geomechanical Modelling for Complex Geological Setting: A Case Study from XGS Field","authors":"Yu Luo, Long-xin Li, Yu Chao Zhao, Rong Wang, A. Younessi, Yongsheng Zhou, Chris Burns","doi":"10.2523/iptc-22988-ms","DOIUrl":"https://doi.org/10.2523/iptc-22988-ms","url":null,"abstract":"\u0000 A 3D geomechanical model is built for the XGS field, located in Sichuan province, onshore China. The field is in a faulted anticline consisting of three main reservoir layers. The main reservoirs are in the crest of an anticline structure bounded between major revers faults. The model captures all the structural complexities and the spatial variation of the geomechanical properties and parameters for the entire XGS field. The structural model is built using the interpreted horizons and faults form the surface seismic tied to the markers interpreted from the well data. The 3D grid is constructed for the entire field, extended to the ground level, to use as a framework for the 3D geomechanical model. The well-centric geomechanical models prepared for the 14 offset wells are used in combination to the surface seismic attributes to model the lithology and petrophysical properties for the entire grid. These data are then used to calculate and propagate the geomechanical properties and parameters. The 3D geomechanical model is designed to captures the spatial variation of pore pressure, in-situ stresses, the rock mechanical properties and parameters. The grid has higher resolution in the main target for the underground gas storage (UGS) operation and its immediate overburden caprock layer. This is done to capture and investigate the vertical and lateral variations in the vicinity of the UGS reservoir in more detail. The rock mechanical properties and parameters are dominantly governed by the lithology. This is while the pore pressure and the in-situ stresses are mainly governed by the geological structure. That has been said, a stress contrast is observed between the shale and carbonate layers. The model suggests that the field is in a strike-slip stress regime. The reservoir rock which consists of fractured dolomite is competent and stiff while the shale caprock is relatively weaker. A comprehensive approach is developed to capture the complexities of the structure and properties of the XGS field. A robust workflow is implemented to propagate the geomechanical properties and parameters to maintain their consistency for the entire studied area.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"42 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121055899","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":"The Effect of Rock Type on CO2 Foam for CO2 EOR and CO2 Storage","authors":"A. Sæle, A. Graue, Z. Alcorn","doi":"10.2523/iptc-22918-ms","DOIUrl":"https://doi.org/10.2523/iptc-22918-ms","url":null,"abstract":"\u0000 CO2 foam is an effective method to reduce CO2 mobility and improve displacement efficiency in CO2 enhanced oil recovery (EOR) and CO2 storage applications. Foam strength and stability are key parameters that influence the efficiency of the foam which depend on several factors including the presence of oil, injection velocity and rock type. The aim of this work was to evaluate the effect of rock type on CO2 foam strength and stability by conducting corefloods with sandstone and carbonate rocks at reservoir conditions. The effect of injection velocity and the presence of residual oil on the foam generation and displacement efficiency was also investigated.\u0000 Steady-state CO2 injections revealed differences in foam generation, strength and stability in sandstone compared to carbonate based on the calculated apparent viscosities. Results showed that the strongest foam was generated in sandstone compared to carbonates because of higher absolute permeability. Drainage-like co-injections with increasing gas fraction showed the relation between rock permeability and the limiting capillary pressure and co-injection at different injection velocities revealed shear-thinning foam rheology in both rock types. Despite stronger foam generation in sandstone, unsteady-state CO2 injections showed similar oil displacement efficiency in both rock types. CO2 foam increased oil recovery by 200% in both rocks compared to CO2 injection without foam. In addition, foam showed a significant impact on water displacement compared to pure CO2 injection which is advantageous for CO2 storage applications. Water recovery during CO2 EOR was 60% in sandstone and 88% in limestone. Dissolution of calcite was observed in limestone, which increased pore space and the CO2 storage capacity. Overall, the results indicate that CO2 foam generation, stability and coalescence are sensitive to rock permeability and pore geometry in the conducted experiments.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125960603","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":"Secondary Versus Tertiary Polymer Flooding: A Laboratory Evaluation in Low Permeability HT/HS Carbonate Reservoir Conditions","authors":"M. Ould Metidji, Jose Luis Juarez Morejon, Maria Flor Garcia Mayoral, Maria Rosario Rodriguez Pardo, Jesus Montes Ruiz, Damien Lereau, Jorge Monzon Vazquez, G. Dupuis","doi":"10.2523/iptc-22908-ms","DOIUrl":"https://doi.org/10.2523/iptc-22908-ms","url":null,"abstract":"\u0000 Polymer flooding is a well-established EOR technique widely implemented in sandstone reservoirs. Sulfonated acrylamide-based copolymers recently proved their potential in harsh HT/HS carbonate reservoirs with pilot tests upcoming in the Middle East. While polymer flooding is often classified as a tertiary recovery method, the present study aims to evaluate EOR efficiencies in secondary and tertiary recovery scenarios. The polymer selection process and characterization in porous media are described in detail.\u0000 The study was conducted on a lab-scale at a temperature of 120°C. The salinity of seawater used for injection was 42 g/L TDS. The polymer selection was based on a thorough rheology and filterability study. The coreflooding tests were performed on limestone outcrops with permeability in the range of 40 mD. Single-phase experiments were performed to evaluate the impact of a pre-shearing step and study the in-situ rheology. Secondary and tertiary oil recovery experiments were conducted using reservoir dead oil. In all experiments, the tracer method was used to determine dynamic adsorption.\u0000 The rheology and filterability study identified the best candidate (SAV 10) among three different molecular weight polymers containing the same high-sulfonation level. The target viscosity for the desired mobility ratio was 3 cP at 120°C, achieved with a polymer concentration of 3500 ppm. The single-phase experiments suggested that pre-shearing the polymer reduced the apparent shear thickening at high velocities due to a reduction in viscoelastic properties. The best oil recovery performances were obtained in the secondary mode (polymer flood applied at Swi) with a 15% higher recovery when compared to the tertiary mode (after reaching Sorw). The results correlate with a later breakthrough for the earlier polymer flood case. In both cases the mobility ratio was comparable (0.18-0.20) and much lower than waterflooding (1.5). The polymer dynamic adsorption estimated with the tracer method was about 140 μg/g rock in brine saturated cores, decreasing to ~100 μg/g rock in the presence of residual oil saturation. The in-situ rheology evaluation after stable recovery was reached following polymer flooding (Sorp), evidenced less apparent shear thickening, which could be related to a change in the conformation of the pores in the presence of oil.\u0000 Most studies reported on secondary and tertiary polymer flooding focused on the case of heavy-oil sandstone reservoirs. The present work introduces new insights on early implementation of polymer flooding to optimize oil production by maximizing the performance of the method in HT/HS carbonate reservoirs. Furthermore, our study provides new insights about sulfonated acrylamide-base copolymer rheology in porous media for low permeability carbonate cores.","PeriodicalId":185347,"journal":{"name":"Day 3 Fri, March 03, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128349073","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}