Day 4 Fri, September 06, 2019最新文献

{"title":"Unlocking the Full Potential: The Psychological Factors that Influence the Adoption of New Technologies in the Upstream Oil and Gas Industry.","authors":"Ruby Roberts, R. Flin, D. Millar, Luca Corradi","doi":"10.2118/195724-MS","DOIUrl":"https://doi.org/10.2118/195724-MS","url":null,"abstract":"\u0000 Innovation is critical to the future success of the oil and gas industry. Yet, the sector has a reputation for being conservative and reluctant to adopt new technology with companies sometimes referred to as \"fast followers\". Compared to other sectors, O&G has a set of unique characteristics that has the potential to hinder technology adoption. Research in other industries indicates that there is a range of sector, organizational and psychological factors that can hinder the introduction of new technologies. Evidence from O&G industry bodies indicate that the psychological factors play a key role in technology adoption; not surprisingly, as workers, managers, investors and regulators can all have a powerful influence on an organisation's receptivity to new technology. The psychological factors do not appear to be well understood but may include risk aversion (Wood Review, 2014), lack of ownership and leadership around technology (OGTC, 2018), and an attitude of reluctance to change (Oil and Gas Authority, 2018).\u0000 This new research project is designed to examine how the particular attributes of the upstream oil and gas industry on the United Kingdom Continental Shelf interact with the underlying psychological processes that govern adoption and deployment decisions. The presentation will first outline what can be learned from about the psychological factors that influence technology innovation and adoption from the broader consumer behaviour and human factors literatures. Then the preliminary results of an interview study with stakeholders involved in technology innovation and adoption on the UKCS, will be reported. Roles include senior managers, innovation leads, and end users from a spectrum of established and new comer companies. A summary of the key themes identified will be discussed including personality (e.g. innovativeness), attitude (e.g. risk aversion), cognitive (e.g. risk perception), social (subjective norms) and organisational level factors (e.g. leadership and organisational culture). These results are being used to develop a preliminary framework of the psychological factors that influence technology adoption in O&G and to produce tools and guidelines on how to support the introduction of new technologies.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132170358","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":"Kaombo Field Thermal Performance Test; A New Reference","authors":"J. Rolland, Xavier Henneuse, Benoit Balagué, M. Jackson","doi":"10.2118/195736-MS","DOIUrl":"https://doi.org/10.2118/195736-MS","url":null,"abstract":"\u0000 The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000 m water depth, including subsea production wells more than 25 km away from the production facility. Producing complex fluids within such a challenging environment required demanding thermal performance of the overall subsea asset with both the problematics of steady-state arrival temperature and cooldown. To do so, the transient thermal signature of every subsea component has been evaluated and correlated into a dynamic flow simulation to verify the integrity and therefore, safety of the system.\u0000 A unique design of subsea equipment aims to cover a large range of reservoir conditions. In order to tackle both risks of wax deposit during production and hydrates plug during restart, the whole system was designed to have a very low U-value and stringent cooldown requirements. A dedicated focus on having an extremely low U-value for the Pipe-in-Pipe (PiP) system enables to improve the global thermal performance. The accurate thermal performance predictions from computer modelling were firstly validated during the engineering phase with a full scale test. Eventually an in-situ thermal test was performed a few days before the first-oil to assess the as-built performance of the full subsea network. A well prepared procedure allowed to characterize precisely the subsea system U-value in addition to evaluate the cooldown time of critical components, after installation. The error band was properly assessed to take into account the difficulties of performing such remote measurements from an FPSO.\u0000 The different elements of the qualification procedure were successful, validating the demanding thermal requirement of the subsea system. The validation of the thermal performance of the flowline was fully achieved. Detailed analysis of the test results was performed in order to define precisely the U-value in operations. The as-built performance verification, including all elements of the complex subsea network, allowed to validate the optimized operating envelopes of the production system.\u0000 A detailed qualification process was conducted in order to fulfill one of the most challenging thermal requirements for a subsea development. Thanks to the precise prediction of the flowline insulation performance, the different reservoir conditions are safely handled. The operating envelope of the production system is finally optimized with the confidence from as-built performances confirmation.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132757493","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 New Flow Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset","authors":"S. Hatscher, L. Ugueto","doi":"10.2118/195784-MS","DOIUrl":"https://doi.org/10.2118/195784-MS","url":null,"abstract":"\u0000 The Vega subsea field in Norway has been producing successfully using a continuous Mono Ethylene Glycol (MEG) injection, topped up with corrosion inhibition means. A topside reclamation process allows re-use of MEG, however, limits the possibilities to produce saline water. In order to manage wells producing saline formation water and to increase ultimate recovery, a new flow assurance and integrity philosophy without continuous MEG injection is considered. This paper describes the options on hydrate as well as integrity management and the modifications both on the subsea and topside facilities required to enable an operational philosophy change. This change of the operational philosophy appears feasible, using either timely depressurization or Low Dosage Hydrate Inhibitors (LDHI) as well as a film building corrosion inhibitor in the system.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129821830","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":"Depositional Behaviour of Highly Macro-Crystalline Waxy Crude Oil Blended with Polymer Inhibitors in a Pipe with a 45-Degree Bend","authors":"N. Makwashi, Delcia Soraia David Barros, K. Sarkodie, D. Zhao, P. Diaz","doi":"10.2118/195752-MS","DOIUrl":"https://doi.org/10.2118/195752-MS","url":null,"abstract":"\u0000 Production, transportation and storage of highly waxy crude oil is very challenging. This is because they are usually characterised by high content of macro-crystalline waxes, predominantly consisting of n-alkanes (C18 to C36) that which could cause costly deposition within the wellbore and production equipment. The accumulation of deposited wax can decrease oil production rates, cause equipment breakdown, and clog the transport and storage facilities. Currently, different polymeric inhibitors have been utilised in the oil and gas field to mitigate and prevent wax deposition. However, as of today, there is no distinctive wax inhibitor that could work effectively for all oil fields. One of the objectives of this work is to study the efficacy of a blended commercial wax inhibitor - pour point depressant on wax deposition mitigation in a flow rig designed with 0 and 45-degree bends in the pipeline.\u0000 Standard laboratory techniques using high-temperature gas chromatography (HTGC), rheometer rig, polarized microscope and elution chromatography were employed to obtain n-paraffin distribution, oil viscosity, WAT, pour point and SARA fractions. Series of experimentation were carried out with and without the inhibitor in a straight pipe test section. The severity of wax deposition in the pipeline built-in with a 45-degree bend is compared with a straight pipe. The blended inhibitor was tested at concentrations of 500, 1000, and 1500-ppm, under laminar and turbulent conditions. The crude oil sample was found to be naturally waxy with wax content of 19.75wt%, n-paraffin distributions ranges from C15-C74, WAT and pour point of 30°C and 25°C respectively. The severity of wax deposition in the test section is 43% higher in 45-degree bend compared to straight pipe. However, the severity of the deposition was reduced to 12.3% at extremely low temperature and flow rate. Nonetheless, better inhibition performance was achieved at 25 and 30°C. The wax thickness was reduced from δwax ≈ 0.36mm at 5 l/min to δwax ≈ 0.132mm at 7 l/min at constant coolant temperature (25°C) and 1500-ppm, whereas, no wax deposition was observed at 11 l/min. Mechanisms such as molecular diffusion due to frictional pressure losses, shear dispersion and gravity settling due to momentum change and hydrostatic, alongside with thermal difference are the main drivers for wax deposition in both straight and bend pipe. Whereas, the interaction mechanisms such as the nucleation, alongside with adsorption, co-crystallization, and solubilisation between the new blended inhibitor and the wax crystals provide an improved inhibition performance in the system even at extreme cases.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"412 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131685393","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":"Surfactant Stimulation Results in Captain Field to Improve Polymer Injectivity for EOR","authors":"Adam C Jackson, R. Dean, J. Lyon, V. Dwarakanath, D. Alexis, Anette Poulsen, David Espinosa","doi":"10.2118/195747-MS","DOIUrl":"https://doi.org/10.2118/195747-MS","url":null,"abstract":"\u0000 Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.\u0000 Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.\u0000 The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.\u0000 Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.\u0000 The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126054247","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":"ABB Subsea Power JIP - A Game Changer for Next Generation Subsea Processing","authors":"S. Vatland, S. Ingebrigtsen, J. Pretlove, Henning Nesheim","doi":"10.2118/195787-MS","DOIUrl":"https://doi.org/10.2118/195787-MS","url":null,"abstract":"\u0000 ABB is running a joint project with Equinor, Total and Chevron to develop technologies for subsea power transmission, distribution and conversion. The output will form a critical part of future advanced subsea field developments. As such an undertaking has never been achieved before, it is a journey with considerable learnings to be shared not only upon completion (anticipated by the end of 2019) but also en route.\u0000 The paper will describe steps taken to build confidence along the way that the proposed solution will be fit for purpose when fully launched. Readers will gain insights into the key steps of this cutting-edge project. These include modifying prototypes of the equipment based on rounds of simulations, laboratory assessments (eg accelerated aging, vibration and shock testing) and water testing. Insight will be provided on tedious testing and qualification effort required to achieve the technology readiness level (TRL) required.\u0000 Readers will learn from the challenges experienced in this ground-breaking project and how they were overcome. Insight will be given into the overall challenge of both research/development and qualification of the novel technology developed in the JIP. Findings from testing, including extensive lab testing against industry standards, and the impact on subsequent development will be presented. The paper will eventually share results from extensive joint research work between the partners and ABB. The results are ground breaking and will by the end of the day introduce completely new opportunities for development of subsea fields.\u0000 As a first-of-kind-project, the results gained, and the subsequent technology developed will be of considerable interest to the industry. By the end of the day, the results from this project will be a key enabler for the subsea factory vision envisioned by the industry.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129007874","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":"Atex Vsd, A Booster for Mature Fields","authors":"Jean-Grégoire Boero-Rollo, Jérôme Long","doi":"10.2118/195786-MS","DOIUrl":"https://doi.org/10.2118/195786-MS","url":null,"abstract":"\u0000 In the oil sector, TOTAL should become the \"low cost champion\". This is presently our main challenge as mentioned by our CEO in the strategical document \"One Total, our ambition\". A key to succeed in a mature field such as PNGF North (CONGO) is to convert gas lifted wells into ESP activated wells.\u0000 The ATEX VSD innovation consists of having the electrical module of an ESP activated well located in hazardous area, avoiding high costs that would result from a platform extension (for an electrical room). This innovation was designed by TOTAL E&P CONGO (TEPC) and installed on the YAF2 platform (YANGA field) in June 2018 has enabled to increase the production of the YAM254 well by 250% and its operational efficiency by 25 points. This innovation, which would not be possible without the close cooperation between headquarters and TEPC, could be extended to the entire TEPC subsidiary and thus open doors for new development opportunities for TOTAL brown fields.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"59 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131627137","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":"Utilizing Real-Time Downhole and Along String Measurements During Drilling and Cementing Operations to Improve Managed Pressure Operations in a Complex High Pressure, High Temperature North Sea Well","authors":"T. Brian, A. Hawthorn, D. Groves","doi":"10.2118/195767-MS","DOIUrl":"https://doi.org/10.2118/195767-MS","url":null,"abstract":"\u0000 Several mature fields in the North Sea experience significant challenges relating to high pressures and temperatures accompanied with the infill drilling challenge of very narrow margins between pore and fracture pressures. To navigate these narrow mud weight windows, it is critical to understand the bottom hole pressure. However, in the cases of fractured formations above the target zones, severe losses can be encountered during drilling and cementing operations often leading to the inability to maintain a full mud column at all times and even threaten the ability to reach TD.\u0000 The operator therefore decided to investigate the use of a new acoustic telemetry system that could provide internal and external pressure measurements, (along with other downhole measurements) independently of traditional mud pulse telemetry in the drilling assembly. Real-time distributed pressure data essential to understanding the downhole conditions could therefore be provided regardless of circulation, even under severe losses or during tripping and cementing operations.\u0000 This acoustic telemetry network was deployed on several wells through multiple hole sizes and including losses management, liner running and cementing operations.\u0000 The initial primary purpose of running the network was the ability to monitor the top of the mud at all times, even in significant loss situations. As real-time data was acquired it became apparent that the data could also be used in real-time to aid and help quantify the actual downhole pressures. The use of this downhole data was modified and new calculations designed for simpler visualization of equivalent circulating densities at the shoe, bit and identified weak zones in the well at depths beyond the acoustic tools themselves. This data was used to manage the bottom hole pressure within a 300 psi mud weight window to ultimately enable the well to be delivered to planned TD.\u0000 The tool and calculations helped verify managed pressure connections and subsequent pump ramp up and down operations to minimize pressure fluctuations in the well. Additionally the data was used during dynamic formation integrity testing and to measure and calculate ECD at various positions along the drillstring and casing when downhole PWD measurements were unavailable.\u0000 This paper will describe how the implementation of new technology through the downhole acoustic network was deployed and the lessons learned in how the real-time data was used, changed and adapted in this particular well. Due to this deployment the acoustic telemetry network will now be used on upcoming equally challenging wells and its range of operations expanded to include drilling, tripping and liner cementing operations.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"237 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131243141","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":"Shortfalls Reduction from Optimized Preservation in Ultra-Deepwater; Kaombo Field Real Case Application","authors":"J. Rolland, Romain Devoisselle, R. Daures, P. Glénat, Ludovic Pagézy","doi":"10.2118/195704-MS","DOIUrl":"https://doi.org/10.2118/195704-MS","url":null,"abstract":"\u0000 The FPSO Kaombo Norte came on stream on July 27 2018, offshore Angola. When both its FPSOs will be at plateau, the biggest deep offshore project in Angola will account for 10% of the country's production. Kaombo reserves are spread over an 800-square-kilometer area. The development stands out for its subsea network size with more than 270 kilometers of pipeline on the seabed between 1500-2000m water depth, including subsea production wells more than 25km away from the production facility.\u0000 During the project phase, measures have been taken in order to standardize the subsea design overall including the thermal requirements. By necessity the insulation design of the subsea component is driven by the most stringent part of the development which is then applied throughout the complete system on Kaombo. This inevitably infers that certain parts of the system operate with a built-in margin regarding thermal performance. With an overall objective to optimize the OPEX the use of this margin on some assets generates added-value in the operational phase by reducing production shortfalls through reducing the number of preservations undertaken during life of field.\u0000 In order to improve the overall preservation sequence, crude abilities to delay hydrates formation and/or to transport hydrates have been studied on the coldest fields. It was found that studied crudes present interesting properties to delay hydrates formation. These tests have been performed with crude samples in lab conditions in order to assess the temperature and pressure when hydrates start to form. The results indicate that it is possible to extend the waiting period (i.e. time before launching preservation) well inside the hydrate thermodynamic zone and operating \"safety\" zones have been defined depending of the actual temperature and pressure.\u0000 An optimized preservation sequence postponing the decision point to restart or preserve was finally implemented thanks to:\u0000 An accurate knowledge of the full system thermal performance especially including the weak links The study of crude properties for the most penalizing fields vs. hydrates plug risk\u0000 The methodology implemented is today already field proven and application of the extended waiting period was performed allowing reduction of shortfalls and smooth restart. A significant impact is expected for the full life of the field.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"295 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132700826","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":"Improving Performance in Elgin HPHT Infill Drilling Despite Increasing Challenges","authors":"M. Alahmad, Oliver Eatough","doi":"10.2118/195725-MS","DOIUrl":"https://doi.org/10.2118/195725-MS","url":null,"abstract":"\u0000 Following the significant reservoir depletion on Elgin / Franklin fields since 2007, drilling infill wells was considered to not only be high cost but also carry a high probability of failure to reach the well objective. The recent campaign on the Elgin field, one of the most heavily depleted reservoirs worldwide, demonstrated that infill drilling can be achieved safely while improving performance.\u0000 Drilling of HPHT infill wells on the Elgin field faced increasing challenges arising from the reduction of reservoir pressure that changed the stresses in the formations above and influenced the overall pressure regime. This stress reorganization in the overburden has affected the fracture network in these formations resulting in reduction in Fracture Initiation Pressure (FIP) and increase of gas levels.\u0000 Challenges were faced during the drilling of three wells in the 2015-2017 campaign. Loss events in Chalk formations in the intermediate sections significantly decreased the already Narrow Mud Weight Window (NMWW). A strategy to define and validate the minimum required MWW in 12-1/2\" and 8-1/2\" sections was developed following a complex subsurface well control event. Managed Pressure Drilling (MPD) technique was extensively used to safely manage gas levels and assess pore pressure.\u0000 Reservoir entry with more than 850 bar of overbalance remains the main challenge in infill drilling. A total loss event during first reservoir entry in the latest campaign confirmed the limitations of wellbore strengthening mud and stress caging materials available today.\u0000 Lessons learned from each well in this campaign were implemented to address these challenges and improve performance. This paper describes the Elgin HP/HT infill drilling experience and the specific techniques and practices that were developed to address these challenges and improve performance. The importance of Equivalent Circulating Density (ECD) management with very narrow MWW, successful high gas level management with MPD and depleted reservoir entry, shows that even in a highly complex environment, drilling performance can be improved allowing for further economical development drilling. The successful and safe delivery of the Elgin 2015-2017 infill drilling campaign demonstrates this at a time the industry moves toward unlocking the reserves of more challenging HPHT fields.","PeriodicalId":332235,"journal":{"name":"Day 4 Fri, September 06, 2019","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126382294","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}