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Journal articles on the topic "Environmental aspects of Offshore oil well drilling"
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STAN, Marius, Valentin Paul TUDORACHE, Lazăr AVRAM, Mohamed Iyad AL NABOULSI, Claudiu TĂNASĂ, and Georgeta ALECU. "Elements constituent for the design of a riser system in areas deep water and extreme deep water applied for offshore drilling." EMERG - Energy. Environment. Efficiency. Resources. Globalization 6, no. 3 (2020): 127–44. http://dx.doi.org/10.37410/emerg.2020.3.10.
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Riser systems are integral components of the offshore developments used to recover oil and gas stored in the reservoirs below the earth’s oceans and seas. These riser systems are used in all facets of the development offshore process including exploration and exploitation wells completion/intervention, and production of the hydrocarbons. Their primary function is to facilitate the safe transportation of material, oil and gases between the seafloor oceans and seas and the marine platform. As the water depth increases, the working conditions of this system becomes challenging due to the complex forces and extreme environmental conditions which are impacting the operational mode as well as the stability. In this paper several aspects concerning riser mechanics and the behaviour of the riser column will be evaluated against different operational situations.
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Duarte, Victor Magalhães, Luciano Matos Queiroz, Ednildo Andrade Torres, and Asher Kiperstok. "Energetic aspects and opportunities for reusing water on offshore platforms in Campos Basin, Brazil." Ambiente e Agua - An Interdisciplinary Journal of Applied Science 12, no. 5 (August 23, 2017): 786. http://dx.doi.org/10.4136/ambi-agua.2121.
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In the drilling and production of oil at sea, a large quantity of potable water used is most commonly transported to oil platforms using offshore supply vessels (OSVs). Sea water desalination is used as well, but only in a few oil platforms. To minimize energy consumption, water supply options were studied. The desalination of seawater and the reusing of streams of grey water and black water were evaluated and compared with the characteristics of the current supply via OSVs. In both desalination and OSV water supply options an electrolytic wastewater treatment plant is used. The objective of this study was to analyze the current situation regarding water supply on offshore platforms located in the Campos Basin, Rio de Janeiro, Brazil, and to propose measures to take advantage of opportunities to reuse water and reduce energy expenditure. Two alternative scenarios were developed that involved the reuse of water that comes from the effluent of a biological wastewater treatment plant (WWTP). Information on the logistics of supplying water to platforms was obtained through direct consultation with companies and sources in the literature. The results show that annual energy consumption (uptake, treatment, transportation, use and waste water treatment) of water on offshore platforms is currently 1.89 GWh, and that a reduction of 1.8 GWh of the energy consumed can be achieved using advanced reuse treatments. Energy consumption in the water reuse treatment is more competitive than those of transport by OSVs or seawater desalination.
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Ndubuisi Elizabeth Chinyerem and Eguzoro Chika.Chelsea. "Environmental and living organisms’ disaster caused by discharge of drilling fluid waste." World Journal of Advanced Research and Reviews 22, no. 1 (April 30, 2024): 393–400. http://dx.doi.org/10.30574/wjarr.2024.22.1.1082.
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The oil and gas industry plays a vast and vital role in our society. Despite the numerous benefits of the production of crude oil, its activities pose a lot of dangers to the environment and living organisms because it generates a huge volume of solid and liquid wastes, thus, these wastes require treatment before disposal. The major drilling wastes are drilling muds, drilling cuttings, and obnoxious gas emissions. Parameters that should be considered during the disposal of decontaminated drilling muds and drill cuttings are heavy metals. These wastes are introduced into the environment through accidental spills as well as intentional discharge. The discharge into the environment has effects on humans, plants, birds, soil, and also aquatic life. Generally, oil based drilling fluid usage and disposal are not preferable. However, water based drilling fluid and synthetic based drilling fluid can be a technically and economically disposed because they are biodegradable. Generally, drilling waste disposal options are offshore disposal, onshore disposal and drill cuttings re-injection. Zero discharge can achieved by drill cuttings re-injection. However extensive study must be carried before drill cuttings can be re-inject to the formation. Disposal options must be evaluated based on economics, environment and operational aspects. This study aimed at evaluating the heavy metals present in the drilling fluid waste and drilling cuttings. The experiment was achieved with the aid of a Flame Atomic Absorption Spectrophotometer (FAAS). Upon the investigation, it was discovered that lead concentration in drilling cuttings was the highest with the concentration of 1,058.9 mg/l and drilling fluid was 190.3 mg/l whereas NUPRC limit is 5 mg/l; the total chromium concentration in drilling cuttings was 19.16 mg/l and drilling fluid was 8.38 mg/l whereas NUPRC limit is 8 mg/l; zinc was 58.10 mg/l in drilling cuttings while in drilling fluid it was 23.96 mg/l whereas NUPRC limit is 50 mg/l; silver concentration in drilling cuttings was 14.67 mg/l and drilling fluid 0.91 mg/l whereas NUPRC limit is 5 mg/l; Cadmium concentration in drilling cuttings was 2.17 mg/l and drilling fluid was 1.36 mg/l whereas NUPRC limit is 1 mg/l. In no doubt. The study has shown that disposal of this drilling fluid waste and drilling cutting directly into the environment without treatment will be detrimental to the living organisms and therefore should be discouraged.
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Di Martino, Gianluca, Roumen Sankoff, Craig Marshall, and Bobby Chopra. "The Coniston development: another offshore challenge in Western Australia." APPEA Journal 54, no. 2 (2014): 475. http://dx.doi.org/10.1071/aj13048.
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This extended abstract discusses the key challenges associated with the Coniston development; particular emphasis is on engineering, operations, and project management aspects. The Coniston development will produce oil and gas from the Coniston and Novara hydrocarbon accumulations, located in permit WA-35-L, about 100 km north of Exmouth, in water depths of about 400 m. The Coniston development will consist of a sub-sea tieback to the existing Van Gogh sub-sea infrastructure and the Ningaloo Vision FPSO, currently producing from the Van Gogh Field. The project was sanctioned by Apache in 2011 and will be on production in 2Q 2014. To maximise reservoir exposure, multilateral wells will be drilled, and completed, employing inflow control devices of latest generation and monitoring production with the installation of tracers. To take advantage of project synergies, gas lift will be provided by Van Gogh wells through a dedicated gas production manifold. The Coniston development represents a remarkable multidisciplinary effort to develop a relatively small-size oil reservoir offshore WA. Some of the challenges achieved are the high oil viscosity, the complexity of the engineering to install new sub-sea infrastructure while minimising the impact on Van Gogh production and maximising the synergies of the tie back, the constant increase in drilling and facilities costs while maintaining attractive project economics, and the more stringent regulations environmental permits and the ability to optimise drilling and operation to achieve production as quickly as possible.
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Olugu, Ezutah Udoncy, Kuan Yew Wong, Jonathan Yong Chung Ee, and Yslam D. Mammedov. "Incorporating Sustainability and Maintenance for Performance Assessment of Offshore Oil and Gas Platforms: A Perspective." Sustainability 14, no. 2 (January 12, 2022): 807. http://dx.doi.org/10.3390/su14020807.
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The existence of external two-fold pressure regarding competitiveness and sustainable development in a capital-intensive industry supports the need for sustainable performance. However, endeavors to create a sustainable framework to measure the performance of the oil and gas (O&G) industry are mostly devoted to the production and supply chain of petrochemical products and rarely focus on a maintenance perspective. Motivated by such scarcity, the goal of this research was to discuss and articulate the performance assessment framework by integrating concepts of maintenance and sustainability in the O&G industry. This study proposed the use of a range of performance measures for assessing sustainability on offshore production and drilling platforms. The conceptual framework consists of four aspects of sustainability categorized into technical, environmental, social, and economic dimensions. Each measure was assigned according to its relevance at the strategic, tactical, and functional levels of maintenance decision making. The conceptual framework resulted in hierarchical clusters of twelve strategic indicators. These indicators consist of conventional measures as well as new ones relating to the safety and reliability on offshore platforms. The potential contribution of the present study is found in its intention to empower a better understanding of sustainable maintenance and encourage those making decisions about practical implementation within the O&G industry. This paper culminates with directions for future studies.
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Ziegler, Robert. "Technology Focus: High-Pressure/High-Temperature (March 2022)." Journal of Petroleum Technology 74, no. 03 (March 1, 2022): 79–80. http://dx.doi.org/10.2118/0322-0079-jpt.
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What a difference a year can make. Oil and gas prices have reached and stabilized at levels that have not been seen for over half a decade, demonstrating that the adage “low oil prices are the remedy of low oil prices” is still true. Let us now see if we are again at the cusp of a new period of exuberance and if the cyclical nature of oil prices could soon show its grim face once more. A key industry discipline required to delay, or maybe even avoid, another price collapse is the planning and execution of high-pressure/high-temperature (HP/HT) projects. Perhaps the movement of some financial institutions toward considering environmental, social, and governance aspects when deciding to fund oil and gas projects will provide the beneficial longer-term stabilization of the current oil and gas price levels. More than ever, the saying “the easy/cheap oil is over” is true, and that requires a more-stable economic environment than we had in past years to assure the world’s uninterrupted energy and chemical feedstock supply, an important share of which will come from HP/HT reservoirs. For this year, I think we can see where the activity currently is from the available HP/HT related papers of the past year or two. A predominance of papers came from Chinese companies enthusiastically embarking on these challenging projects to secure their domestic energy needs and reporting their technology innovations and learning curves in interesting case studies. I was able to find some geographic diversity by including case studies from the Middle East as well, where good ideas and innovative low-cost approaches have enabled economically feasible project delivery in tough times. Notably absent in the choice of papers were the traditional HP/HT areas of the deep Gulf of Mexico and the North Sea. But maybe the more favorable oil and gas prices will spawn some new activity in these areas as well, if the regulatory and fiscal environment also improves. Reading this year’s case studies, some of the more experienced engineers among us will notice that, on some occasions, known challenges have been encountered that, in our experience, had been successfully mitigated in previous projects. This is likely a weakness from the Great Crew Change, where the knowledge preservation and transfer may not always have happened satisfactorily. The cut-throat cost-saving environment of the past few years, combined with the worldwide health crisis leading to curtailed travel and many workshops and conferences being canceled, certainly contributed to this lack of information flow as well. This is why it is so important to engage in SPE through online interest/discussion groups to find the necessary expertise in our pool of members. With this recommendation, I hope you will read the 2022 featured papers with interest and take them as encouragement and a source of good ideas for the years of greatly improved activity levels before us. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 20148 - Solid Management Optimization for Offshore Big-Bore HP/HT Sour Gas Well Cleanup by Ardian Nengkoda, Saudi Aramco, et al. SPE 199052 - One of the Deepest Wells Drilled in Bolivia: High Pressure and Temperature in More Than 9 Months of Drilling, No Casing Wear Detected by Russell Mertens, WWT International, et al. SPE 202250 - Next-Generation Ceramic Sand Screens as Openhole Completion Solution in High-Rate Erosive and Corrosive Well Environment at Dvalin HP/HT Field, Offshore Norway by Robert Ritschel, Wintershall DEA, et al.
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Carpenter, Chris. "Machine-Learning Algorithms Optimize Drilling-Center Locations Offshore." Journal of Petroleum Technology 75, no. 10 (October 1, 2023): 72–74. http://dx.doi.org/10.2118/1023-0072-jpt.
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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211772, “Optimizing Future Drilling-Center Locations Using Advanced Analytics and Machine-Learning Algorithms Offshore Abu Dhabi,” by Rail Salimov, Benoit Jaffres, and Jamal Alblooshi, ADNOC, et al. The paper has not been peer reviewed. _ Long-term development planning requires infill drilling. Because of the limited number of slots in the offshore environment, new drilling centers (wellhead towers) are required. Optimized location of drilling centers can play a major role in reducing drilling expenses. Two main challenges related to wellhead-tower placement are discussed in the complete paper: first, where to place future drilling centers based on subsurface coordinates and drilling constraints; and second, how to allocate dozens of subsurface targets to multiple drilling centers. The drilling-center placement optimization algorithm developed by the authors is based on multiple optimization parameters related to well cost. Introduction To finalize well trajectories, and thus best manage well costs, before the drilling phase, the following detailed analyses are required: - Evaluation of horizontal trajectory in terms of landing point and total depth - Optimization of horizontal drain length - Optimization of the horizontal drain length in the best oil-bearing zone - Torque-and-drag evaluation - Anticollision assessment - Selection of optimal completion accessories However, for most giant offshore fields with complex plans, hundreds or even thousands of infill developments are required. Definition of optimal locations and allocations of wells to drilling centers will require multiple iterations of already tedious work. An alternative methodology is described in the complete paper that allows finalization of future facility placement with the use of open-source machine-programming tools and applied mathematics. The presented methodology was deployed successfully on two major offshore fields where current production is connected through wellhead towers. Evolution of the development plan and the ramp-up of production means that additional drilling is planned during the next 10 years. Approximately 100–150 development wells are planned to be drilled from yet-to-be-constructed wellhead towers. One of the main challenges in achieving cost efficiency is effective placement of the new towers to minimize the total drain length of all development wells. The methodology covers the two most important aspects of facility construction that play vital roles in optimization of capital investment in facility expansions of offshore oil and gas fields. These aspects are optimized allocation of future wells to drilling centers and placement of those drilling centers.
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Deryaev, Annaguly. "Engineering aspects and improvement of well drilling technologies at the Altyguyi field." Naukovij žurnal «Tehnìka ta energetika» 15, no. 2 (April 30, 2024): 9–20. http://dx.doi.org/10.31548/machinery/2.2024.09.
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The relevance of the research is justified by the rapid development of the oil industry, which requires constant improvement of methods and equipment to increase extraction efficiency and reduce environmental impact. The aim of this study is to enhance the current engineering aspects of drilling in the Altyguyi field while considering increased productivity and reduced environmental impact. Among the methods used, it is necessary to mention the synthesis method, abstraction method, generalization method, induction method, deduction method, classification method, and others. This study examines the technological aspects of operating wells in the Altyguyi gas-condensate field. Extensive laboratory and industrial research on the properties and composition of oil, gas, and condensate was conducted to properly implement the dual completion technology for gas extraction from one formation and oil extraction from another formation in a single well. By implementing advanced drilling methods, including horizontal and multi-hole drilling, as well as using modern drilling fluids, it was possible to improve well productivity and reduce drilling time. As a result of technology optimization, the overall efficiency of the oil and gas extraction process in the field has been increased, confirming the significance of innovation implementation for improving results in the oil industry. These enhancements not only increased drilling safety and efficiency, but also reduced the negative impact on the environment, emphasizing the importance of integrating modern technologies with environmental considerations in the oil extraction process. This research makes a significant contribution to the development of more efficient and environmentally sustainable drilling methods in oil fields, contributing to increased oil extraction productivity and reduced environmental impact
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Noussia, Kyriaki. "Global Offshore Energy Installations: Implications for Environmental Pollution Liability Insurance in Relation to Major Oil Spill Incidents." European Energy and Environmental Law Review 32, Issue 2 (March 1, 2023): 100–111. http://dx.doi.org/10.54648/eelr2023005.
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Post the Deepwater Horizon (DWH) incident, offshore energy insurance underwriters reassessed their risk exposures in response to newly perceived operational risks involving blowouts, fires, explosions, lost control of well and other non-hurricane risks. Already in the aftermath of the DWH incident, it has been noted that it would be crucial to consider the willingness of the global offshore energy insurance market to participate in efforts to establish and fix a new liability limit for environmental pollution liability insurance. In relation to the approach followed by the USA administrations, this has been fragmented, with the current administration in office introducing a moratorium on new oil and gas leasing on federal lands and waters and in terms of its policy relating to its climate agenda. Against this background, this article describes the insurance implications of environmental pollution liability in case of offshore drilling operations incidents (such as the DWH) resulting in major oil spills. In doing so it discusses in detail the legal framework and the position in the EU and draws a comparison with other jurisdictions. It also contains proposals for future measures so as to be able to offer better insurance coverage for such offshore drilling disasters, such as the introduction and collection of data on damages, or an EU wide and an international agreement especially focusing on offshore-related incidents with a transboundary character, as well as a mechanism to facilitate early compensation payments to potentially vulnerable victims.
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Carpenter, Chris. "Integrated Work Flow Aids Data Digitization, Management for Offshore Drilling." Journal of Petroleum Technology 73, no. 10 (October 1, 2021): 49–50. http://dx.doi.org/10.2118/1021-0049-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202290, “Digital Documentation and Data Management for Offshore Drilling,” by Zhong Cheng, SPE, Xi’an Shiyou University and CNOOC, and Rongqiang Xu and Xiaolong Yu, CNOOC, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. The industry is expending significant effort into using instrumentation and software to optimize operations in all domains for exploration and production to move toward the digital oil field. The complete paper describes an integrated geological-engineering data-management project covering all aspects of well-engineering work flows, with the objective of providing a continuous improvement platform to users. Introduction CNOOC has spent more than 20 years on the progression of information construction. A private cloud platform was completed in 2018, and the characteristics of oil and gas data and critical storage-management technologies were studied systematically. At the same time, nearly 20 kinds of drilling- operation analysis software have been developed independently. From the perspective of engineering technology, these provide real-time monitoring, remote decision-making, technical training, and other information resource services and support for offshore drilling operations. However, the following problems restrict the efficient operation of such projects: - Because of the lack of a unified data-integration-application platform, data sharing has not yet been realized. - In the process of real-time monitoring and remote decision-making, more engineering information based on drilling operations lacks the support of geomechanical data. - The knowledge base and case library to guide the prevention and handling of drilling-operation accidents have not been established. System-Target Analysis The design goals of the platform are embodied in three aspects: function, safety, and operability, while system performance requirements are summarized as adaptability, response speed, scalability, maintainability, and the effective-ness of failure-handling mechanisms. According to the functional requirements of different users for offshore-drilling cloud technical services, users generally are divided into three categories: headquarters decision-making managers, drilling-operation project teams, and system-operation and maintenance-service providers. System Construction Goals and Architecture Construction Goals - Chief among these was to build a geological-engineering integrated data-management platform. Another important goal was to build a case-management platform. An intelligent search engine is established to retrieve the corresponding disposal knowledge through a comprehensive information model. A knowledge-management subsystem is established, and users are linked with internal knowledge-management processes with the help of the cloud. The specific operation process is carried out in the private cloud, and the results are fed back to the user through the human/computer interface.
Books on the topic "Environmental aspects of Offshore oil well drilling"
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Investigations, United States Congress House Committee on Interior and Insular Affairs Subcommittee on General Oversight and. Relationship between offshore oil drilling and the proposed Pacific Palisades onshore drilling project: Oversight hearing before the Subcommittee on General Oversight and Investigations of the Committee on Interior and Insular Affairs, House of Representatives, One Hundredth Congress, second session ... hearing held in Santa Monica, CA, October 24, 1988. Washington: U.S. G.P.O., 1989.
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West Coast Offshore Exploration Environmental Assessment Panel. Offshore hydrocarbon exploration: Report. [Vancouver, B.C.]: The Panel, 1986.
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Marcovitz, Hal. Is offshore oil drilling worth the risks? San Diego, CA: ReferencePoint Press, 2011.
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Western Australia. Environmental Protection Authority. Wesminco Oil Pty Ltd WA-149-P offshore oil production: Environmental Protection Authority report. Perth, W.A: Dept. of Conservation and Environment, 1985.
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United States. Minerals Management Service. Pacific OCS Region. Delineation drilling activities in federal waters offshore Santa Barbara County, California: Draft environmental impact statement. Camarillo, Calif: The Region, 2001.
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Office, Canada Federal Environmental Assessment Review. Offshore hydrocarbon exploration: Report. [Ottawa]: Minister of Supply and Services Canada, 1986.
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Holing, Dwight. Coastal alert: Ecosystems, energy, and offshore oil drilling. Washington, D.C: Island Press, 1990.
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Patin, Stanislav Aleksandrovich. Ėkologicheskie problemy osvoenii͡a︡ neftegazovykh resursov morskogo shelʹfa. Moskva: Izd-vo VNIRO, 1997.
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Resources, United States Congress House Committee on Natural Resources Subcommittee on Energy and Mineral. The Minerals Management Service's proposed five-year program for oil and gas leasing on the outer continental shelf: Oversight hearing before the Subcommittee on Energy and Mineral Resources of the Committee on Natural Resources, U.S. House of Representatives, One Hundred Tenth Congress, first session, Thursday, June 28, 2007. Washington: U.S. G.P.O., 2008.
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United States. Minerals Management Service. Alaska OCS Region. Proposed Norton Basin lease sale 100: Final environmental impact statement. [Anchorage, Alaska]: The Region, 1985.
Find full textConference papers on the topic "Environmental aspects of Offshore oil well drilling"
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Ribeiro, Paulo R., and Otto L. A. Santos. "Well Control Research and Development." In ASME 2012 31st International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2012. http://dx.doi.org/10.1115/omae2012-84032.
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Well control has been an inexhaustible source of research/development/innovation for the past four decades due to its impact in oil and gas exploration and production. Such an importance is based on three pillars: i) human safety, ii) environmental protection, and iii) economic issues. Macondo incident has proved that continuing development of the subject is an issue to be tackled by oil companies to preserve and also rebuild their image to society. One of the most important aspects of well control is the development of kick simulators capable of handling increasing complexity of well geometry (diameters and trajectory), drilling fluids (synthetic drilling fluid), well location (land and offshore) and wellbore conditions (increasing pressure and temperature severity with depth). Such simulators have the following missions: i) to help the drilling engineer to make decisions during well control procedures and kick situations, ii) to provide personnel training and certification and iii) to guarantee a better understanding and interpretation of field observations. The main objectives of the present work are three-fold: i) to present an overview of the evolution of kick modeling and simulation over the years, ii) to focus on the R&D efforts of the joint work of academia and industry to build a well control model to handle deep and ultra-deepwater drilling challenges and iii) to present a software based on that model to assist drilling engineers during well control operations. Experimental data has been based on PVT measurements of gas and synthetic drilling fluid mixtures under HPHT conditions. Phase behavior modeling has proved to be a very important issue to be taken into account in the two-phase flow model that represents the kick circulation process. The current work presents the results of the interaction of experimental lab work and numerical modeling to develop a kick simulator to handle complex drilling scenarios to assist drilling personnel in well control operations.
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Wang, Kunjian, Pengfei Liu, Xinxin Hou, Pan Wang, Pei Zhu, Mingxuan Hao, Dejiang Li, et al. "Drilling and Completion Waste Reutilization and Zero Discharge Technology Used in China Bohai Bay." In SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205633-ms.
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Abstract With the increasingly stringent national environmental rules, waste produced in drilling and completion process is forbidden to be discharged into the Bohai Bay or reinjected into the formation. The current disposal method of drilling and completion waste in Bohai Oil field has some problems such as high cost, low efficiency and high HSE management and control risk. Faced with these problems, drilling and completion waste reutilization and zero discharge technology has been developed and applied in this region. In order to reutilize drilling and completion waste which include cuttings circulated from formation, wasted drilling and completion fluids, the following aspects are carried out: Firstly, drilling platform is upgraded to meet the zero discharge requirement: solid control system is modified, cuttings closed transfer system and cuttings treatment system are equipped on the platform to collect and dispose the waste. Meanwhile, recovery and disposal capacity to support different spud drilling are assessed: cuttings transport capacity is up to 15m3/h, which can meet the highest requirements of 12-1/4″ hole drilling when ROP is up to180m/h. Secondly, the well profile is downsized to reduce the production of cuttings, mud and other wastes from the root, which can also improve efficiency and yield cost. The field application shows that the amount of the waste has been reduced by 41.39%, 39.86% and 41.52% in first, second and third spud drilling, and average ROP is 35%, 28%, 42% higher than similar wells drilled before. Lastly, in drilling and completion fluids system optimization and reutilization aspects, environmentally friendly drilling and completion fluids with low solid content are developed. The experiment shows that the properties of the liquid phase after solid-liquid separation can be reused, and the solid phase with low water content is easy to pack and transport back to land. Drilling and completion waste reutilization and zero discharge technology introduced in this paper has been successfully applied in more than 40 wells, and the volume of waste drilling fluid is reduced by 80%, which is a trade-off between zero discharge and well construction cost. This technology can also be applied in other offshore oilfield which is inevitable as the environmental rules become more and more strict.
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Nunez Davila, Andres Felipe. "Innovative Performance Models for Integrated Projects in Offshore Deepwater Operations." In Gas & Oil Technology Showcase and Conference. SPE, 2023. http://dx.doi.org/10.2118/214064-ms.
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Abstract Integration in offshore drilling environments was traditionally limited to bundled services and managed by a project manager. The success of the integration model was mainly related to equipment logistics and quality assurance. The objective of this paper is to describe how the traditional model has evolved from a bundled long-term service commercial relationship to the innovative performance award model that has been implemented in an integrated project in the Gulf of Mexico. The offshore and deepwater drilling environment is characterized by its high operating cost; thus, risk management is one of the key aspects for the project's success. The oil and gas industry has continuously evolved during the last decades, moving toward digital and automation technologies and applications. The new performance model is based on a time definition and further estimation of budget required. Factors are linked to specific rewards in case the predefined objectives are achieved. The associated risks definition becomes critical to ensure the predefined estimates are achievable. To support the risk management process, the application of digital solutions support the planning and execution stages. The multiwell performance analysis and benchmarking tool enables us to evaluate the historical results and comparison between rigs, including and not limited to determining the project baseline, identifying the historical invisible lost time, and defining the main areas of improvement. This tool supports the definition of the risks factors and provides the inputs to determine the most accurate project budget. For the execution, one of the historical associated risks was related to the drilling fluids and well integrity. It is commonly found in the area for wells to be drilled under narrow operating windows and having extended sections. The increase of frequency and accuracy of drilling fluid properties verification is fundamental to ensure the system is under the required parameters and properties limits previously determined. The automated rheometer has been developed to increase the frequency and accuracy of rheological drilling fluid properties, thus minimizing the impact of one of the most relevant risks across the area. Finally, the focus to optimize the schedule and logistics was based on synergies developed across the different services involved. This included activities that are carried out from a single point of contact, eliminating the duplication in tasks and minimizing the resources required.
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Akbar, Muhammad Ikhsan, Jerry Tobing, Mohd Zarir Bin Musa, Irshad Fajar, and Fajar Ardiansyah. "Successful and Efficient Drill & Drive Conductor Operation in Offshore East Java." In SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205716-ms.
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Abstracts Conductor setting depth is critical to provide structural support for next drilling sections. The shoe strength must suffice for drilling ahead and avoid any washout and unstable zone. The objective is to design and run conductor smoothly in regards to engineering and operation aspect. Multidisciplinary approach including geotechnical, drilling engineering, and structure, was implemented during planning strategy. The pre-determined conductor setting depth was defined on the maximum mud weight to be used during drilling surface hole section in accordance to the formation strength below the conductor with the purpose of not inducing losses to the formation. Lateral distance between conductor and platform jacket pile was also analyzed to secure the jacket integrity. Anti-collision analysis was performed to prevent collision due to the existence of production well in same platform. Conductor pipe size and specification with some feature was defined to withstand under anticipated load and environment. To determine the way to achieve target depth and the suitability of hammer type, drivability analysis was performed with various anticipated condition. Considering shallow refusal depth, drill and drive was required to reduce shaft friction of soil. Another environmental challenge arise during conductor operation was unable to contain fluid and cutting returns from clean-out process causing return to cover part of the production platform facility. Some of technology were planned to mitigate this challenge. By having comprehensive conductor design, the conductor pipe in all four wells drilled has been successfully installed without any problem on platform jacket integrity and subsequent drilling section. This approach also enabled to efficiency of conductor installation where the number of clean-out and driving run could be reduced. The overflow return challenge could be fully contained by utilizing selfdesigned equipment. The overall operation days of conductor has shown improvement with 1.02 saving days on the last well which equivalent to amount of cost saving around USD 203,500.
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Koning, Maartje, Vedran Zikovic, Kaj Van der Valk, Rajesh Pawar, John Williams, Nils Opedal, and Alexandra Dudu. "Development of a Screening Framework for Re-Use of Existing Wells for CCUS Projects Considering Regulatory, Experimental and Technical Aspects." In Middle East Oil, Gas and Geosciences Show. SPE, 2023. http://dx.doi.org/10.2118/213583-ms.
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Abstract Oil and gas fields that have reached their end of economic life provide a potential option for geologic CO2 storage in support of the energy transition and efforts to reduce CO2 emissions. Re-use of these existing wells can potentially result in significant cost savings compared to drilling new wells, but also presents a challenge for CCUS (Carbon Capture, Utilisation and Storage) development. Prior to conversion, evaluation of the feasibility of re-using existing oil and gas wells will be required, including consideration of operational and safety requirements. Currently, there are no standard approaches or public tools available to aid in the technical evaluation and to support decision making on well re-use potential for CO2 storage. The REX-CO2 (Re-using EXisting wells for CO2 storage operations) project, funded by the ACT (Accelerating CCUS Technologies) program has developed a first-of-its-kind assessment framework and evaluation tool based on state-of-the-art practices, standards, guidelines and international reference projects. The tool is designed to utilize available data on well construction, subsurface geology, well operational and integrity history to screen the re-usability of wells for CO2 storage operations. The tool provides a thorough qualitative evaluation of the current re-usability potential of existing wells and highlights the most important issues requiring further detailed analysis. The results can be used to design and select mitigation options, ultimately identifying the most promising candidate wells. The tool has been applied to multiple international case studies with tens of wells, both onshore and offshore, covering a wide range of well designs and subsurface settings. The overall goal was to test and demonstrate the evaluation process, identify remediation activities and providing a high-level cost benefit analysis. The tool has recently been applied successfully in the Middle East region for one of the national oil companies, showcasing the assessment framework and identifying potential remediation activities to safely convert a selection of wells into CO2 injectors. The tool development is supplemented by experimental research focused on well cement integrity due to its role as a well barrier element. The emphasis is on mechanical and chemical degradations and damage processes on well barrier elements, including investigation of novel self-healing and active remediation measures. In addition, state-of-the-art research on the conditions of well materials expected in CO2 injection wells have been described, providing recommendations for material selection in a CO2 CCUS storage setting. Lastly, the project evaluated the regulatory and environmental frameworks, permit requirements and social perspectives related to re-using existing oil and gas wells for CO2 storage. All aspects (technical & non-technical) have been integrated in a final set of recommendations to provide insights into the factors that need to be addressed when considering existing wells for re-use in CO2 storage operations.
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Barrera, Edison, Carlos Perez, Jose Manuel Gomez, Jose Alarcon, Maria Andrea Torres, Abelardo Zapata, and Pedro Laguado. "Risk Mitigation and Drilling Time Reduction Practices with Optimized Wellbore Geometries Implemented in Offshore Shallow-Water Tertiary Wells in Gulf of Mexico." In International Petroleum Technology Conference. IPTC, 2024. http://dx.doi.org/10.2523/iptc-23495-ms.
Full textAbstract:
Abstract Well construction operations in the Gulf of Mexico involve a high level of complexity in a high-risk environment. Although multiple operators and service companies have been drilling for decades and technology has evolved throughout this time, the wells targets become more challenging to drill and the technical level along with the economical benefit require new approaches to make projects profitable. One of the key aspects to make drilling projects successful is risk evaluation and engineering applications to deliver producing wells efficiently. The offshore fields in the Gulf of Mexico require custom wellbore architecture and drilling practices to optimize time on well delivery without compromising well integrity standards and safety. This paper describes the successful implementation of a performance enhancement process and risk mitigation strategies applied in optimized wellbore geometries in shallow-water fields in the Gulf of Mexico, for which customized de-risking engineering and drilling practices were introduced to accelerate well delivery. The subject fields in the Gulf of Mexico are considered as strategic in the development plan, in which the main drive is time optimization for early oil production, resulting in additional risk management planning.
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Mesra, Jodi, Ziad Talat Abu Libdi, Takahiro Toki, James Wood, and Tajrul Shaheer Tajudin. "Improving Well Completion Operations on the First Five Zone Smart Completion on Multi-Lateral Well in Offshore Abu Dhabi." In ADIPEC. SPE, 2022. http://dx.doi.org/10.2118/211749-ms.
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Abstract Reducing the number of wells along with the associated capital expenditure, while increasing the production capabilities, has been the target for most of the major oil operators operating in the mature field environment. Wells completed in multi-layered reservoirs with multi-lateral compartments using Extended Reach Drilling techniques has become common practice within offshore Abu Dhabi. Combining smart completion and multi-lateral technology has been proven to be one of the optimum solutions to achieve the well objectives. However, this increases the well complexity and subsequent risk. This paper outlines the recent success story of the first five-zone smart completion, performed in offshore Abu Dhabi. This paper will also highlight the challenges faced, and subsequent lessons learned throughout the installation and operational phases. Achieving a successful well completion installation of a five-zone smart completion in a highly deviated well, with multiple hydraulic and Tubing Encapsulated Cable (TEC) lines in a multi-lateral well involves detailed planning in order to reduce the potential risks and challenges. In order to mitigate these completion challenges, detailed optimizations and improvements were harnessed to increase the success rate and minimize the risk. These optimizations included all aspects of completion design, equipment selection, equipment preparation and completion execution. Simplifying the well design, optimizing the job sequence, and well-planned completion installation procedures assisted with the efficiency of the operation and the overall outcome. Well completion was safely executed ahead of the planned time and achieved the required well integrity requirements. Zonal isolation between flow control valves (FCV), completion tubing, and multiple gas lift mandrels (GLM) were all tested and confirmed as integral. All eight control lines in the completion were tested and confirmed as integral based on the function testing the flow control valves. The permanent down hole gauges (PDHG) were also fully tested before installation and readings taken pre/post installation to confirm their functionality. The successful installation of this well has shown that an optimized well design along with preparation is the key factor to achieving success for a complex smart completion. A well-planned job execution similarly played a crucial factor in this installation. Utilizing proper running equipment, rig space management, and managing the multiple control lines, was also a key factor. This was further complemented by having well-trained service personnel, who were supported onsite during the execution phase which impacted the overall success of the installation. There were, however, some aspects to the operations that require improvements, and this has been captured for any future operations. This paper presents the practices used throughout the well design, and equipment preparation /installation that were adopted over the entire well completion to achieve the key objectives. It also highlights some challenges that were seen during the installation, and operations that allowed for the delivery of a quality completion. All the key learnings from this install, were captured as lessons learned and will be considered for improvements for any future well designs and operations for the future.
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Naharindra, Adhi, Mohd Hisham Abd Hamid, A. Ghafar A Halim, Sarah M Affandi, W. M. W Ibrahim, Ahmad Fadhli Ismail, Nurul Nadia Abu Bakar, et al. "Application of Tubing Stem Test as Alternative Low-Cost Solution for Dynamic Reservoir Evaluation: Case Study from Appraisal Well in Offshore Malaysia." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21834-ms.
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Abstract This paper demonstrate a unique combination of techniques and equipment that enabled dynamic reservoir evaluation process using simplified Drill Stem Test (DST) string and completion accessories. The well testing was conducted on a shallow slanted offshore well, drilled into faulted reservoirs with multilayer and complex fluids environment. Key technical challenges to perform well testing includes designing a custom DST string to cater for the multilayer reservoir and articulating a surface well testing equipment that capable of efficient separation to ensure safe and environmental friendly disposal while having accurate flowrate measurements, to deliver good interpretable data given that the uncertainty and complexity of the formation and the well itself. During drilling campaign, contingency plan to mitigate against losses was implemented which had a significant impact on the well testing program. As such, uncertainty-based well test design and interpretation methodology was used to address this and to achieve well objectives. This involved numerical model analysis considering reservoir uncertainties and their interaction with each other, to identify which parameters can be interpret confidently and to indicate the test duration for the well testing program. Since the area is nearby to producing fields, several cases model based on reservoir pressure regime was also constructed during the design stage to tolerate flexibilities for the decision tree. The well testing was successfully conducted result from integrated approach to well test design and realtime data support throughout the operation along with innovative DST string design, customize completion accessories for multiple zones testing and adaptive intervention tools for highly deviated well. Matching with nearby wells were also conducted during monitoring to predict future pressure behaviour which allow for the duration of final build-up to be optimized. Given that Health, Safety and Environment (HSE) is the top of priority, an important aspect of the surface well testing package was the water treatment equipment to treat the produced water from reservoir before being discharge in order to guarantee safe environmental disposal. The well was successfully test at maximum flowrate 2,000bpd of oil and 20MMscf/d of gas with traces of produced water. Data gathered thru the Tubing Stem Test (TST) can used to interpret reservoir parameters and all the well testing objectives were successfully achieved despite the many challenges encountered during the drilling campaign and design stage. The end results may contradict traditional testing methods for pressure transient analysis, but hopefully this paper might create the opportunity to replicate TST as quick and effective reservoir evaluation in other parts of the world.
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Wahbah, Salima, Samir Bellah, Tadataka Hattori, Ryuchi Tsuda, Asim Mumtaz, Potshangbam Sanathoi, Mahmoud Hameed, and Mohammed Rawy. "Improving Drilling Safety and Efficiency with 100% Reservoir Exposure in a Challenging Low Resistivity Mature Reservoir Associated with Structural and Geological Uncertainties by Integrating Extra Deep Azimuthal Resistivity Technology in a Source-Less Solution - A Case Study From UAE Offshore." In International Petroleum Technology Conference. IPTC, 2024. http://dx.doi.org/10.2523/iptc-24097-ms.
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Abstract Improvement in drilling efficiency and maximum reservoir exposure are two key considerations in determining the success of a well. Detailed planning covering these aspects is critical, especially when the reservoir is associated with a complex geological setting. In this case study, oil producers in a complex low resistivity environment associated with high heterogeneity, karstification, caves, collapsed holes, fractured and faulting as common geological features were drilled on the flank of a mature field. Drilling challenges would be profound if the well bore passed through the sub-seismic karst features and the overlaying shale formation. Drilling into such features risk drilling complications that could potentially result in unwanted sidetracks and/or reduce reservoir exposure. The main challenge was to maximize reservoir exposure in the target interval, characterized by thin pay thickness, while maintaining a safety buffer of 15 to 20 ft between the overlying shale and the well trajectory. Maintaining a standoff from an uncertain oil-water contact (OWC) was also critical due to prolonged production in the field. Historically, a combination of a high-resolution resistivity-imaging service with nuclear magnetic resonance technologies was utilized for drilling the lateral sections in this area, primarily for fluid typing, permeability, porosity distribution, and detailed geological evaluation. However, this solution was insufficient for proactive geosteering to place the wellbore optimally in the reservoir and map the sub-seismic structural changes and the uncertain OWC. To overcome these challenges, Extra Deep Azimuthal Resistivity (EDAR), along with reservoir navigation services was integrated into the existing solution after completing feasibility studies based on the offset data. The feasibility study demonstrated that EDAR could map the structural and fluid changes from the wellbore satisfying drilling and well placement requirements. EDAR inversion mapped the structural changes on top of the reservoir, reducing the geological uncertainty related to sub-seismic faults, karsts, and the OWC. This enabled informed geosteering decisions to achieve 100% reservoir exposure in the optimum target zone and helped to maintain a smooth well profile facilitating a trouble-free completion operation. Placing the well in the best porous zone of the reservoir resulted in a 28% increase in ROP. The completion design was optimized based on fluid distribution analysis and structural information from EDAR inversion. The acquired data improved the knowledge of the geological setting of this area.
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Djanuar, Yanfidra, Qingfeng Huang, Jimmy Thatcher, and Morgan Eldred. "Integrated Field Development Plan for Reliable Production Forecast Using Data Analytics and Artificial Intelligence." In Gas & Oil Technology Showcase and Conference. SPE, 2023. http://dx.doi.org/10.2118/214021-ms.
Full textAbstract:
Abstract Having a robust field development plan (FDP) for mid-size mature oil fields generally poses considerable challenges in the context of the integrational elements of production forecast, operational environment, projects and surface facilities. An integrated FDP combined with data analytics and artificial intelligence (AI) has been introduced and deployed in a heavily compartmentalized offshore field of Turkmenistan. An integrated approach through data-centric analytics and AI has been proposed for an optimal FDP. It consists of four aspects: model integration, time-series forecast (TSF) of production, AI-assisted operation-schedule generation, and evaluation and selection of scenarios. Firstly, model integration is performed as bringing together both multi-discipline raw data from field measurement and their interpretations that change non-linearly. Secondly, model integration aids in the application of AI for production forecast. A unique AI technique was built to allow raw data and interpretation. Illustratively, the model is capable of forecasting decline curves matching the history production. Meanwhile, engineers’ production forecast inheriting from simulation, machine learning or type curves is also constructed by understanding how/why human-driven forecasts differ from the measured decline and incorporating those insights. In addition, AI-assisted scheduler efficiently allocates resources for operational activities, considering the well planning nature, intrinsic operation properties, project planning process, surface facilities and expenditures. Resources are thus utilized for optimal schedules. Finally, evaluation and selection of FDP scenarios take place by considering the multidimensional matrix of factors. Multiple scenarios are generated and scored, reacting to the change of factors. AI-powered optimization is availed to recommend the most efficient tradeoffs between production and carbon generation. The implementation of the integrated FDP approach has been successfully applied for the generation of production profiles and operation schedules, which reduces the time by 80% and increasing accuracy by 55%. Production forecast for existing wells and future wells proved to be reliable. It achieved the production targets with proper allocation of schedules, by considering multi-discipline constraints. Through AI-assisted scheduler, different types of rigs were properly assigned to the planned wells, which requires additional rigs based on the outcome. The model was agile to the change and sensitivities of wells requirement, projects uncertainties and cost changes. The optimum FDP scenario was recommended for the business decision, operation guide and execution. This approach represents a novel and innovative means of integrating and optimizing FDP considering complex factors using AI methods. It is efficient in merging raw data and interpretations for model integration. It accommodates changes and uncertainties from multiple aspects and efficiently generates optimum FDP in a few days rather than months for giant fields. It is the first robust tool that unites subsurface properties, reservoir engineering, production, drilling, projects, engineering and finance for the corporate FDP.