Day 4 Thu, May 09, 2019最新文献

{"title":"Considerations and Strategies for Financing Integrated LNG-to-Power Projects","authors":"Béla Viertl, D. Guccione","doi":"10.4043/29662-MS","DOIUrl":"https://doi.org/10.4043/29662-MS","url":null,"abstract":"\u0000 The role of liquefied natural gas (LNG) in the global energy system is increasing. In 2000, 11 countries were importing LNG. By 2017, that number had risen to 40 (International Gas Union, 2017). In the Middle East alone, LNG imports have increased by more than 380% over the last three years (S&P Global Platts, 2017). This trend is expected to continue as countries throughout the region, along with others across Asia, Africa, and South America seek to capitalize on cleaner burning and abundant natural gas supplies worldwide.\u0000 With increasing population growth and deficits in power generation capacity in many developing parts of the globe, the LNG-to-power concept has emerged as an important driver of future sustainability. However, the costs involved in transitioning power projects to make use of LNG are enormous. One significant challenge that these projects face is the co-development and potential co-financing of the LNG plant, along with supply, distribution and underlying power infrastructure. LNG-to-power projects can also potentially suffer from \"project-on-project\" risk due to the interdependency of the construction and commissioning of facilities and infrastructure.\u0000 Overall, the ability to secure financing from a variety of debt and equity sources throughout the project lifecycle is critical to success. Innovative project financing structures allow for the generation of large debt capacities, while passing project risk to the lenders. In such cases, sponsors are able to assume limited recourse after project start-up and in many cases, enjoy flexibility of loan repayment, thus contributing to overall project economics. Co-financing also alleviates investment risk and helps raise capital at a relatively low cost, which benefits sponsors and investors alike. Financing solutions must be tailored to meet the needs of the project, with risk and returns being borne by the sponsor and different classes of investors (i.e., equity holders, debt providers, quasi-equity investors, etc.).\u0000 This paper will discuss the many challenges that must be addressed in order to bring LNG-to-power projects to life, with a particular focus on the unique risk elements that are presented to lenders and investors throughout development.","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115421315","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":"Comparison of Coupled and Decoupled Seismic Analysis of TLP Piles","authors":"H. Suroor, Amir Arablouei","doi":"10.4043/29546-MS","DOIUrl":"https://doi.org/10.4043/29546-MS","url":null,"abstract":"\u0000 Tension-leg-platforms (TLPs) are increasingly being used in offshore regions of high seismicity. The TLP foundation typically consists of very long driven piles supporting the TLP tendon loads. These piles experience significant uplift loads generated by the inherent system buoyancy. API RP 2T is considered the industry standard for TLP design which provides guidance on foundation design; however; available guidance on seismic design of TLP foundations is limited. The focus of this paper is to present and compare two types of seismic design methods for TLP piles and discuss associated outcomes, which should provide greater insight into the complexities involved in seismic design analysis.\u0000 The seismic analysis of TLP piles can be performed in two ways; coupled and decoupled analysis. In a conventional decoupled analysis, as practiced in the industry, the foundation pile is analyzed independent of the TLP structure considering various design loading conditions, including seismic loads. In the coupled analysis, the entire system including TLP structure, tendons, and piles are modeled and analyzed as one integrated system. This is done to investigate both system and component responses due to the impact of seismic ground motions. In the coupled approach, the system can be analyzed by the response spectra method for an extreme level earthquake (ELE) and the dynamic non-linear analysis for an abnormal level earthquake (ALE). The effects of seismic kinematics and inertia, soil degradation due to cyclic loading, soil damping, etc. are considered in both types of analyses.\u0000 Two case studies are presented where these methods have been applied for two TLP projects located in seismically active regions. The outcome of the study is to present a comparison between the conventional decoupled approach and the proposed coupled seismic analyses of TLP piles. This comprehensive seismic study aims to provide detailed insight into the seismic design methods of a TLP foundation to supplement the design guidance presented in API RP 2T. Although complex and time consuming, the proposed coupled approach provides greater insight into the system response.","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124818897","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":"Analysis for Selection of Tubular Connections for HPHT Gas Well Completion","authors":"Jiandong Wang, Huali Zhang, Yufei Li, Dajiang Zhu, Chuanlei Wang","doi":"10.2118/190981-MS","DOIUrl":"https://doi.org/10.2118/190981-MS","url":null,"abstract":"\u0000 Currently, in high pressure and high temperature (HPHT) gas well, the selection of tubular connection is based primarily on ISO13679 standard. However, based on well failure investigation, connections which meet ISO13679 CAL IV test requirement, may not meet the needs of high temperature and high pressure as well as high corrosion environment gas wells. It is therefore necessary to revisit the fitness-for-service analysis and assessment methodology based on downhole working condition. For example, there were 44 development wells in petrochina southwest oil and gas field a block. Among them, 35 wells had the annular filled with anomaly pressure, leading to the tubular failure rate at 80%. During the production, serious leakage was found due to the tubing connection fracture and seal failure. When comparing the downhole working conditions with the ISO13679 standard,the main difference was found to be the coexistence of internal and external pressures under the varying axial load and temperature in different operation stages, and the existence of environmental corrosion. In this paper, Finite Element Analysis (FEA) model was established to study the premium connection limit tolerance. The analysis revealed the connection stress distribution, the seal contact pressure, as well as length change due to the different makeup torques. The minimum make-up torque was analyzed to study its impact on the seal contact pressure and length change of connection under the working conditions. In addition, different make-up torque conditions were analyzed to study the impact of the vibration load that may cause connection fatigue failures. In premium connections, the reverse shoulder is generally used. The analysis found that the greater shoulder reverse angle and shorter sealing length may reduce the ability to resist the torque due to the plastic deformation in the shoulder. It was found that as the compressive stress reached to greater than 80% of the material yield strength, the corrosion rate increased significantly, causing possible seal failure. However,the test method was not conformity with the coexistence of internal and external pressure in downhole in ISO13679 international standard. The FEA found that the connection seal ability to gas significantly decreases as the external pressure increases under axial load. The FEA also found that as the tubing string lateral vibration load becomes more than 9g acceleration, the fatigue endurance limit of connection reduces to less than 10 million times. The paper identifies that the coupling thread is prone to fatigue fracture and the seal prone to leakage failure. Therefore, it is recommended that make-up shoulder interference laps be controlled for premium connection with reverse angle shoulder. Under tension and high external pressure, test and analysis are required to verify the gas seal of premium connections, to meet resistance requirement to avoid the thread fatigue fracture and seal leakage under lateral ","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130507155","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":"Egina Deep Water Completion Operations Continuous Improvement Achieved by Implementing Process Optimization Practices","authors":"Kenneth Johnson, Christophe Morand, M. Williams, V. Okengwu, V. Chaloupka, Romain Djenani, C. Okpalla, A. Achich","doi":"10.4043/29595-MS","DOIUrl":"https://doi.org/10.4043/29595-MS","url":null,"abstract":"\u0000 The Egina project has delivered best-in-class upper and lower completions, utilizing deep water completion experiences, global best practices, and lessons learned using a \"factory\" approach providing robust completion processes. Continuous improvement throughout the completion process was achieved through process optimization practices that contributed to the overall success of the project. Lower completion (LC) times have been reduced by 60 % between the first and 26th well, while reducing upper completion (UC) times by 40 % for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies (OE), and run reliabilities (RR), exceeding 98 %. Mechanical skins average approximately 2.5, while productivity/injectivity indices recorded 26 wells, during initial flowback and injection testing, average around 150 B/D/psi (325 m3/D/bar).\u0000 Standardized completion designs identified the fundamental process tasks and estimated cycle times associated with those tasks. A disciplined process approach was maintained to help minimize potential risks—by using Failure Mode, Effects, and Criticality Analysis (FMECA) and Failure Risk Analysis (FRA)—during all stages of the project, anticipating requirements and potential issues. Implementation of lessons learned from previous deep water operations during the project was fundamental to design optimization and the allocation of local resources. Following in the spirit of a \"factory\" approach in executing the completions, all times for tasks and subtasks were captured from the onset of project inception, allowing the project team to establish benchmark task times, while demonstrating continuous improvement throughout the project.\u0000 The project has delivered best-in-class completions, leveraging deep water completion experiences and referencing global best practices and lessons learned. Fundamental tasks for both the lower and upper completions were identified as the areas where the most significant efficiency improvements could be gained. The team developed a data tracking process to help ensure tasks and subtasks were monitored during the completion process, allowing the project to establish best practices. Statistical analysis of lower and upper completion tasks and subtasks was constantly monitored, with results communicated to the team. Since project kickoff, lower completion run rates have been reduced by 60 % between the first and 26th well, while reducing upper completion rates by 40 %. Well construction durations currently average 24 days per well, and lower and upper completion operating efficiencies and run reliabilities exceed 98 %.\u0000 The project established Key Performance Indicators (KPIs) for fundamental tasks monitored during the completion process, establishing benchmark metrics for each while monitoring continuous improvement. Reviews of these tasks within the completion process for completed wel","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121559703","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":"An Enhanced Assembly for Management of Open Hole Deepwater Standalone Screen Injector Completions","authors":"M. Williams, V. Okengwu, Patrick Patchi Bourgneuf, Modem Guan, T. Roane, V. Chaloupka","doi":"10.4043/29666-MS","DOIUrl":"https://doi.org/10.4043/29666-MS","url":null,"abstract":"\u0000 A major operator with two large projects in Africa has been using a unique subassembly design, called the dual-isolation assembly (DIA), positioned on the bottom or toe of an open hole stand-alone screen (SAS) completion. The main objective of the DIA is to enhance the circulation process for washdown capabilities and provide efficient management and removal of the filter cake for the subsequent improvement of injectivity rates by lowering formation skin values on the injector wells.\u0000 After providing high-rate washdown through the float shoe at the toe of the completion, the DIA provides a means of circulating a filter cake removal treatment for the open hole. Once the filter cake treatment has been circulated sufficiently, the service tools are retrieved from the completion to surface. For an injector well, the flow path into the formation would be through the sand-control screens and the float shoe from the inside. Since the float shoe incorporates spring-loaded valves that would normally open during injection and close when pumping stops, it is beneficial to lock the valves out of service to prevent long term spring fatigue that could cause the valves to remain open at some point during the life of the well, allowing flow back of formation material inside the screens. After treatment of the open hole, an additional function of the DIA is to close the barrier isolation valve to isolate the formation while the filter cake treatment is activating.\u0000 As a continuation of an earlier paper (Roane, et al. 2018), the DIA has met all expectations on all 19 wells where it has been implemented in Africa. Due to enhanced procedures, the mechanical skins have averaged 2.5 and injectivity indices have averaged above 140 (B/D/psi) on these wells. Installation times have continually improved during the project due to following best practices.\u0000 In addition to fulfilling the requirements of these standalone screen (SAS) completions, the DIA design addresses other potential challenges, such as the prevention of hydraulic locks and formation swabbing, which can be detrimental and problematic to open hole completions. Other characteristics of the DIA that benefit open hole management were realized during the course of the project, such as the capability of the DIA to wash through the interior of the isolation barrier valve prior to closing the valve. Once closed, the valve can be re-opened and re-closed as required.\u0000 An important aspect of the physical attributes of the DIA that benefits logistics and running speed of the completion is its compact design allowing it to be completely assembled in the shop and shipped to location, such that it is a single pickup and makeup on the rig floor. This benefit has been exhibited by continual improvement in completion installation times throughout the project.","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"36 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131141006","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":"Integrated Monitoring Approach for Offshore Geological CO2 Storage","authors":"Joonsang Park, A. Blomberg, Ivar-Kristian Waarum, C. Totland, E. Yakushev, G. Pedersen, G. Sauvin, Luke Griffiths, E. Eek, L. Grande, A. Walta, B. Bohloli, M. Soldal","doi":"10.4043/29324-MS","DOIUrl":"https://doi.org/10.4043/29324-MS","url":null,"abstract":"\u0000 Measurement, monitoring and verification (MMV) are vital to ensure the conformance and containment of geological carbon storage (GCS). This requires cost-efficient and multidisciplinary approaches. To investigate this challenge in an offshore environment, we have studied and tested different monitoring approaches, covering seismic, electromagnetic, micro-seismic, active and passive sonar, and chemical sensing methods. The studies in the manuscript are based on laboratory- and field-scale tests. The data of our current interest are various as mentioned above, and for both deep- and shallow-focused monitoring. We measured laboratory geophysical data in the scenario of CO2 flowing through a fracture in a sandstone core sample (De Geerdalen Formation, Svalbard, Norway) to see the possibility of detecting leakage. The field-scale feasibility was also demonstrated through a synthetic modeling study. Laboratory acoustic emission tests were performed with North-Sea relevant rock samples to evaluate the micro-seismic applicability to offshore GCS monitoring. Acoustic and chemical sensor technologies are considered essential for marine monitoring of the seabed and water column, but knowledge and documentation on how to optimally use and combine these technologies is scarce. During a recent controlled CO2 release experiment, we have investigated the performance of different acoustic and chemical technologies for application to GCS monitoring. By quantifying the capabilities and limitations of different acoustic and chemical technologies, we aim to provide operators with the knowledge needed to maximize monitoring performance while minimizing the number of sensors and costly operations.\u0000 First, it was learned through a laboratory rock physical test that electromagnetic signal is relatively sensitive to CO2 flow through fracture (and potentially faults as well) compared to seismic. The acoustic emission tests showed that reservoir sandstone core samples are subjected to induced seismicity, whereas the cap-rock or shale are rather quiet during these tests. To be conclusive, more tests and data analysis are required. Nevertheless, the up to date result indicates that detection of leakage in shale only via micro-seismic might be challenging. Initial results from the cotrolled experiments releasing CO2 to the water column indicate that a small amount of CO2 in gas phase may be detected from a large distance (100s of meters) using a broadband echo sounder. Passive acoustic detection of a small leak (1.15 l/min) was feasible from a distance of 10m. A plume of dissolved CO2 was detectable using chemical CO2 and pH sensors placed 4-10 m from the origin of the leak, when releasing CO2 at a rate of 5-6 l/min. Finally, we have investigated how to integrate the deep-focused geophysical and shallow-focused seafloor monitoring techniques. In our study, we have used a set of leakage scenarios (leakage path, rate, etc.) available in the literature. In addition, we have inc","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"76 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132820284","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":"Impacts of Fiscal Systems on Oil Projects Valuation","authors":"R. Lucchesi","doi":"10.4043/29568-MS","DOIUrl":"https://doi.org/10.4043/29568-MS","url":null,"abstract":"\u0000 Despite increasing demand for cleaner energy around the world, oil is still the main global energy source and this scenario will not change in the short term. Together with natural gas, they supply 57% of world primary energy demand (BP, 2018). Therefore, if a country wants to benefit from having its hydrocarbon reserves developed to generate wealth, it is crucial to enable economic conditions for such. This study aims to show the impact that distinct fiscal systems adopted by each country can have on the valuation of an oil field and its commercial feasibility, from an international oil company perspective. Fiscal terms define, among other things, how revenue from oil production is shared between operators and the host country. To investigate such topic, a deepwater offshore oil development project was valuated using discounted cash flow method. Sixteen scenarios were created, considering a combination of four distinct field sizes under four fiscal systems, selected from some of the world's top oil producing countries. For each scenario, internal rate of return (IRR), which indicates the project's economic return for the operator, and government take (GT), which indicates how much of the oil revenue is directed for the host country, were calculated. Findings show very distinct results in each scenario, with IRR for operators ranging between 8 and 21% and government take between 57% and 84%. Considering that project returns should always be higher than a company's capital cost, in some scenarios the discovery would not be declared commercial. Results also show that, in general, large oil development projects in countries with tax/royalty system present a higher return for the operators, while production-sharing contracts tend to generate a higher government take. This shows that the same oil field, under same geological conditions, can offer very different economic returns to the operators and host governments, depending on the fiscal system in place. In some cases, the fiscal system has such an impact on the economic feasibility of the project, that it may even prevent the discovery to be declared as commercial and, therefore, not be developed and booked as proven reserves. The main takeaway of this study is that understanding fiscal systems is an essential tool for operators to properly evaluate its projects and one of the most important features governments can adjust to attract private investment to their oil industries.","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"63 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115441289","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":"Wear and Its Effect on Electrical Submersible Pump ESP Performance Degradation by Sandy Flow: Experiments and Modeling","authors":"Haiwen Zhu, Jianjun Zhu, Zulin Zhou, R. Rutter, Hong-quan Zhang","doi":"10.4043/29480-MS","DOIUrl":"https://doi.org/10.4043/29480-MS","url":null,"abstract":"\u0000 Multi-stage electrical submersible pump (ESP) is a frequently used artificial lift method, especially in high production wells. Severe wear and leakage can be caused by sand production from unconsolidated sandstone and proppant backflow. The loss of boosting ability and system stability under sandy flow condition is hard to be predicted, which not only reduces the production but also causes severe failures. In this study, a closed testing flow loop with a mixed type ESP is constructed to test pump performance and efficiency under water-sand flow. 64 hours total testing time is divided into several short intervals. After each interval test, the deteriorated head and efficiency of ESP with pure water were tested. More head loss was observed under low flow rate region, which is presumably caused by leakage through the secondary flow region. Head curve acquired in the test is compared to other studies to analyze the leakage effect in different regions. A leakage flow map including three different regions is provided. The seals’ ID/OD and clearances were measured after the pump was disassembled. The leakage effect in previous mechanistic ESP performance prediction model is modified based on test results. By using the appropriate geometries, the deteriorated head curve can be calculated. Compared to the test curves, the proposed model agrees well with the head degradation trend. The model can be further improved by adding abrasion and efficiency models with more available data.","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"355 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115932737","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":"How Digital Technology and Standardisation Can Improve Offshore Operations","authors":"Bjarne L. Tofte, O. Vennemann, Farquhar Mitchell, N. Millington, L. McGuire","doi":"10.4043/29225-MS","DOIUrl":"https://doi.org/10.4043/29225-MS","url":null,"abstract":"\u0000 This paper explains how digital technology combined with standardisation is used to improve Subsea 7's offshore operations with the aim to avoid incidents, increase efficiency and reduce cost and schedule.\u0000 A new way to write, use, and complete offshore installation task plans has been developed. Using an electronic database and application-based system, Electronic Task Planner (ETP), hard copies will become redundant. Integration of Standard Task Plans (STP) in the ETP enables re-use of procedures, ensuring best practices are consistently applied during offshore operations, and will significantly reduce time to produce and review documents. The system will auto-generate as-built documentation and input to the vessel daily progress reports.\u0000 Offshore operations are supported by means of 3D virtualisation technology and animations. VR models are used to visualise the work environment for familiarisation and for design and procedure planning. 3D models can easily be integrated into the VR environment, combined with vessel and ROV models from the 3D model library to quickly analyse a proof of concept for the engineering planning.\u0000 An emulation room and testing lab has been set-up, and by creating virtual models of the vessels, control systems can be effectively tested under near to \"live\" conditions. By integrating a physics engine into the emulator system, projects can be verified against expected sea states and can confirm the control system will allow project operations to be completed. Using the emulation techniques means operators can be trained on exact same virtualised control system software in advance of actual construction, or control functions can be tested before delivery to the vessel. The same model can also be used to facilitate efficient planning and familiarisation of deck operations.","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"52 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124223194","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":"Finding the Repeatability in One-Off Projects to Improve Performance","authors":"R. Shenoy","doi":"10.4043/29405-MS","DOIUrl":"https://doi.org/10.4043/29405-MS","url":null,"abstract":"\u0000 Project teams generally believe that large oil and gas capital projects typically have unique scope and are comprised of highly customized elements. For this reason, when they hear about new technical frameworks, such as Project Production Management (PPM) (Shenoy & Zabelle, 2016), sometimes described as \"applying manufacturing techniques to projects\", it leads them to believe such methods only apply in scenarios with highly repeatable and predictable conditions in tasks and processes. Consequently, many experienced project professionals find it difficult to see how to apply PPM. They mistakenly believe that PPM implies a \"manufacturing approach\" and reject it as appropriate for the work activities in capital projects.\u0000 We show that large capital projects in oil and gas have a lot of inherent repeatability, using a well-known analysis of processes and products called the Product-Process Matrix (Hayes & Wheelwright, Link Manufacturing Process and Product Lifecycles, 1979) (Hayes & Wheelwright, The Dynamics of Process-Product Lifecycles, 1979). We use this observation to show Project Production Management applies to the execution and delivery of all projects, large or small, customized or standardized, and will improve upon prior conventional project management practices.\u0000 Project Production Management is based on the operations research foundation of production systems. We elaborate upon this foundation underpinning the PPM framework, showing how it allows one to take advantage of repeatability occurring in project work activities in different forms – knowledge, process and products. We start by identifying the assumptions of repeatable knowledge implicit in the disciplines used in conventional project management. We review the prior literature and taxonomy of a production system. All manufacturing systems are production systems. However, not all production systems are manufacturing systems. Manufacturing systems are but one type of production system. We explain that the belief that PPM is a simple application of line flow – also known as high volume manufacturing – is an overly simplistic characterization of PPM. A deeper analysis of the work activities of projects shows different types of production systems embedded within a typical project. Describing the work activities encountered in a project as a set of inter-connected production systems makes them amenable to the modeling and analysis tools of PPM, such as Little's Law and Kingman's Formula, which can be used to predict the limits of project execution and where best to manage variability by the strategic allocation of buffers such as capacity, inventory and time. We illustrate the concepts by identifying examples of repeatability present in an actual oil and gas capital project, an offshore rig.","PeriodicalId":214691,"journal":{"name":"Day 4 Thu, May 09, 2019","volume":"78 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129891442","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}