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Liu, Yihua (School of Naval Architecture & Ocean Engineering, Dalian University of Technology ) | Li, Hongxia (School of Naval Architecture & Ocean Engineering, Dalian University of Technology ) | Huang, Yi (School of Naval Architecture & Ocean Engineering, Dalian University of Technology )
In this paper, the new concept polar ocean nuclear energy platform was introduced and the influence of the moonpool on its towing resistance was studied. STAR-CCM + was used to calculate the towing resistance of the nuclear power platform at different towing speeds when the moonpool was at both open and closed. It can be found that towing resistance increased obviously with the increase of towing speed. The existence of the moonpool tends to disorder the flow field around the platform, which will cause a 20%-30% increase on the nuclear power platform's towing resistance. The research on the mechanism of increasing the resistance of the lunar moonpool can provide some guidances for the design of nuclear energy platform in the future.
In recent years, as the global warming continues unabated, the arctic sea ice gradually melts, and regular navigable waters appear in summer. It is highly possible that the arctic ocean will be ice-free in summer of 2050 (LI Z.F., 2019). The ice-free state of the arctic in summer will bring certain economic benefits to the development of the global economy: if the arctic shipping route is used, the sailing time and energy consumption of the route from China to the northern Europe or the Baltic sea will be 1/3 less than those of the traditional route. If the destination is within the Arctic Circle, the sailing time and energy consumption will be 1/2 less (CAI M.J., 2019). In addition, the arctic is rich in natural resources, including 13% of the world's proven oil reserves and 30% of the world's natural gas reserves. If the polar natural resources are to be exploited, the problem of power supply needs to be solved urgently. The ecological environment of the arctic region is fragile (LIU D.H., 2019), and it has high requirements for environmental protection of engineering equipment. The offshore nuclear power platform can provide sufficient, stable and environmentally friendly power (LI X., 2019), which is the best choice for the development of power supply equipment in the polar region and has a broad application prospect.
KBR announced that its joint venture with SOCAR, who is undertaking the engineering design phase of the Azeri Central East (ACE) platform, is now nearing completion. The ACE platform is the first of its kind to be designed through all phases, from concept to front-end engineering design and detailed design, to fully use KBR’s digital twin technology. The benefits of the digital twin continue to be used as the ACE platform moves into fabrication and commissioning, which is being undertaken in Azerbaijan. Digital twin technology creates a platform for all involved in the process to access all project information from anywhere in the world through all phases. The technology allows users to view procurement status and materials availability.
Oklahoma City-based Gulfport Energy plans to shed nearly $1.25 billion in debt as it enters a court-supervised Chapter 11 bankruptcy process, according to a company statement on 14 November. Gulfport operates in the Oklahoma’s SCOOP and Ohio’s Utica Shale and as of the second quarter of this year was operating a single rig in each play. The company formed a new executive team in 2019 which was tasked with trimming costs and improving cash flow. However, Gulfport’s large debt load combined with long-term pipeline contracts meant it was on an unsustainable footing given current natural gas prices, ultimately driving its decision to enter bankruptcy, David Wood, president and CEO of Gulfport, said in the announcement. A prepackaged restructuring agreement was reached with most of the natural gas producer’s credit lenders and senior noteholders.
Securing long-term energy supply for Malaysia is one of the prime responsibilities of PETRONAS; and Malaysia Petroleum Management (MPM) has been entrusted to shape the industry and enable efficient exploitation strategies and optimal development planning of Malaysian hydrocarbon assets. Production sustainability and reserve growth/addition are among the key focus area in MPM; hence, strategies and efforts are being formulated to improve the average oil field RF to more than 40%. Objective assessment of field performance, identification of recovery gaps and defining roadmap to improve field's ultimate recovery factor are critical steps to maximize the field potential ad ultimate value. This paper demonstrates the application of a hybrid workflow, comprising of data analytics-based performance benchmarking and Field Development Plan (FDP) analog assessment, to identify potential development and field management opportunities for improving economic recovery factor of an oilfield.
This novel workflow consists of three key steps. First step involves reservoir performance assessment through application of diagnostic plots, decline trends and pressure/production/injection history to validate existing reserves classified as ‘No Further Activity’ (NFA). NFA reserves along with maturity assessment of undeveloped/contingent resources will provide validated recovery factor for the field. Second step is gap analysis of validated recovery factor against benchmark RF computed through data analytics carried out in Reservoir Performance Benchmarking (RPB) tool. The third and final step focusses on monetizing the RF gap and replicating best development practices through assessment of analogue reservoirs and Field Development Plans (FDPs). Analogue development cases can be from reservoirs within same field or reservoirs with similar complexity index based on RPB tool. This step involves making various cross-plots to identify opportunities like infill drilling, secondary recovery requirement, optimal producer to injector ratio, waterflood & production optimization and operational excellence.
This workflow has been successfully applied to various oilfields (mature & greenfield) within Malaysia and results have been presented in this paper. The workflow has helped to identify numerous development opportunities to improve economic recovery factor e.g. new producer/injector wells, monetization plan for minor oil reservoirs, waterflood optimization and voidage management plans. These opportunities (subsurface/well/surface) are being matured for execution through MPM's enabling processes like Asset Value Framing (AVF), Asset Development Integrated Review (ADIR) and Asset Management Integrated Review (AMIR).
Application of recovery factor improvement workflow coupled with reservoir benchmarking results has facilitated opportunity identification in Malaysian oilfields and defined roadmap to augment nation's oil reserves base and improve the average oil field RF to more than 40%. Using this workflow, RF gap identification in existing oilfields can be completed in relatively short period of time and actionable plans can be framed for maximizing recovery factor of the respective field.
The sustained increase in global demand for cleaner fuels continues to drive the gas industry growth. Liquefied natural gas (LNG) has been a key enabler for this growth by making sizeable remote gas re-serves, which are unreachable by pipeline, accessible to the major and emerging gas markets. Every segment of the LNG supply chain has its own set of technical challenges. On the upstream side, many gas resources require significant pre-treatment before liquefaction, and the feed gas to the LNG facility is typically a mixture of various compositions from multiple sources; this composition mix evolves over the life of the project. The main challenge is development planning for the contributing reservoirs under the constraints imposed by the processing facility– managing reservoir deliverability, scheduling & sequencing of wells, and downtime management while maintaining the inlet stream specification. To aid with long-term planning for such assets, a virtual field management system is needed that can emulate a real-world hydrocarbon producing asset by capturing all operational constraints, resource lim-its, and complex operating logic.
This paper describes a comprehensive field management framework that can create an integrated vir-tual asset by coupling reservoir, wells, network, and facilities models and provides an advisory system for efficient asset management. The field management component can replicate any operational logic, exercises holistic control over the sub-surface model, integrates with the surface network model, and provides optimization capabilities. This paper demonstrates this for a complex LNG asset that is fed by sour gas of different compositions from multiple reservoirs.
We describe the different levels of constraints the asset needs to operate under, including treatment plant capacity, the LNG production capacity, the contractual LNG specifications, the disposal of gas impurities and imposes them on the model by utilizing a flexible and extensible logic framework. Con-straints applied at different levels can be mutually competing and their combination with recovery opti-mization goals increases complexity. The unified field management system uses a robust scheme to bal-ance the coupled system under these constraints while optimizing overall recovery. The optimization is enabled through the ability provided by the field management system to query and retroactively control flow entities during the simulation at the desired frequency.
Customization through scripting was necessary to implement this advanced logic and was enabled by the extensible nature of the field management framework. This extensibility, along with native capabili-ties, ensures that any level of complexity can be captured, and the workflow described in this paper can be applied to any hydrocarbon producing asset for short-term and long-term development planning.
The Ichthys gas-condensate field is situated in the Browse Basin, North West Shelf of Australia, and the field production commenced in July 2018. The Brewster Member, one of the two reservoirs in the field, is a liquid-rich sandstone reservoir. One of the major uncertainties is the degree of well productivity impairment, caused by condensate banking since the dew point pressure is close to the initial reservoir pressure. The objectives of this study are to evaluate the condensate banking impact on well production performance, and to establish a modelling methodology to consider the condensate banking effect in a full-field simulation model, based on the field production data.
Permanent downhole gauges are deployed in the field, and thus, downhole pressure can be monitored continuously. We conducted high rate tests for selected wells to monitor well productivity impairment from the condensate banking. This production data was history-matched with a compositional sector model by applying Local Grid Refinement (LGR) and Velocity-Dependent Relative Permeability (VDRP) to account for more accurate physics in the near-well region. With the tuned VDRP model, skin trends were predicted to increase with various gas rates, and a skin correlation was established as a function of this gas rate. This correlation is applied to the full-field simulation where LGR and VDRP cannot be applied due to a simulation time constraint.
The skin correlation was validated through the history matching, using the full-field model and was used to predict the future field production performance. We need continuous monitoring of the condensate banking effect, to further validate the correlation, because the production data used in this study is less than one-year duration. The correlation is then flexible enough to tune the history matching when necessary.
We present the monitoring and modelling of the condensate banking effect with the actual production data. The implementation of the proposed well modelling will help reservoir engineers in considering the condensate banking effect in the field production forecast.
Cheng, Zhong (Xi'an Shiyou University and CNOOC Ener Tech-Drilling & Production Co.) | Xu, Rongqiang (CNOOC Ener Tech-Drilling &Production Co.) | Yu, Xiaolong (CNOOC Ener Tech-Drilling &Production Co.) | Hao, Zhouzheng (CNOOC Ener Tech-Drilling &Production Co.) | Ding, Xiangxiang (CNOOC Ener Tech-Drilling &Production Co.) | Li, Man (CNOOC Ener Tech-Drilling &Production Co.) | Li, Mingming (CNOOC Ener Tech-Drilling &Production Co.) | Li, Tiantai (Xi'an Shiyou University) | Gao, Jiaxuan (Xi'an Shiyou University)
Upstream Oil & Gas industry recognizes that there are significant gains to be had by the implementation of new digital technologies. For offshore exploration and development, the goal is to bring together all domains, all data, and all engineering requirements in a seamlessly interconnected solution. The industry is putting significant efforts into using instrumentation and software to optimize operations in all domains for exploration and production (E&P) to move towards the digital oil field of the future. an innovative digital solution has been designed and implemented to cover all different aspects of the well planning and engineering workflows, delivering a step change in terms of capabilities and efficiency.
As part of this transformation process, CNOOC have implemented integrated data management project of geological engineering for covering all different aspects of the well engineering workflows, delivering a step change in terms of capabilities and efficiency. The objective is to provide a continuous improvement platform to users for:
Digitalization can reduce the time spent with daily documentation and simultaneously increase the quality by removing an error prone way of work.
Technological solution enabling real-time data transmission from all rigs to CNOOC onshore headquarters and enabling real-time visualizations of the drilling data. This includes workload, number of needed rigs, daily performance, key performance indicators and even operation time forecasts based on real data.
Engineering solution to transform expert experience and accident cases into information to easily identify the areas of operational improvement allowing to implement specific measures to reduce intangible loss time (ILT) and non-productive time (NPT) which can help in reducing costs.
This project has also provided a real geological drilling environment where high frequency real-time drilling data is utilized along with low frequency daily drilling report data to provide better insights for well planning and generate ideas for improving performance and reducing risk.
This paper presents a full description of a new industry standard digital well construction solution that has the potential to transform the well operation process by providing a step change in collaboration, concurrent engineering, automation, and data analytics. Furthermore, the cloud-deployed solution challenges will be briefly discussed.
The learned lessons and gained experiences from this project construction presented here provide valuable guidance for future demands E&P and digital transformation.
As the oil and gas industry enters the digital era, openness is a key enabler to realizing the vision of transforming the industry for the better. The practice of reservoir engineering and reservoir simulation is no exception. In this paper, an openness mechanism in a reservoir simulator using Python scripting language is introduced. It empowers engineers to utilize simulation in new ways. It extends simulator capabilities and enables people to implement flexible-control logic to solve field management challenges.
The new openness mechanism in the simulator allows engineers to program and include Python scripts in a simulation model. These scripts interrogate and interact with the simulator. The scripts are executed by the simulator while running the model. Flexibility is available to execute the scripts at every Newton iteration, before and after every simulation timestep, at specified times, or when a criterion is met. Simulation model properties can be queried through the scripts, such as well connections, well properties, group properties, grid region properties, network entities, current simulation time, etc. The scripts can set properties such as well constraints, well and connection productivity index (PI), group production target, pausing or stopping the run, etc. Customized control logic, if not directly available in the simulator, can be implemented in the scripts that interrogate and drive the simulator. Such customization can be packaged as Python libraries and shared with team members, enabling continuous value creation. Public Python libraries, such as NumPy, pandas and pywin32 or win32com, can also be loaded in the scripts to extend even further what the simulator can do.
The openness mechanism is demonstrated on case examples. They include customized action to acidize wells when production drops, approximating the geomechanical effect of decreasing well pressure, modeling the effect of fines in injected water on well injectivity, and connecting to a network simulator. Examples are also given on customized reporting for model diagnostics and result interpretation, setting production constraints based on economics calculated in an Excel sheet with complex fiscal regime, advanced gas accounting, management of sulphur content, dual-optimization to meet gas demand while honoring oil treatment capacity, and integrated asset modeling from reservoir to surface networks to processing facilities.
the ability to extend built-in functionalities of a reservoir simulator and customize field management controls using user scripting language. It embraces innovation and enables continuous value creation in reservoir simulation.
Organisations have long recognised the potential for diverse teams to improve overall creativity, innovation and productivity, thereby achieving consistently better business outcomes - the so called ‘diversity bonus’. This is particularly true and relevant to the oil and gas industry, which constantly has to manage technical and economic uncertainty, major operating hazards, and continually seek business performance improvement and efficiencies, in order to operate sustainably and meet ever higher stakeholder expectations.
However, developing successful diverse teams presents practical questions and challenges, including what type of diversity will really add value to a task, how will a diverse group of people relate to and support one another, how can major innovation be delivered consistently whilst working within highly structured management systems and standards which aim to achieve a high degree of consistency and minimise failure frequency, and what is the most useful role of the manager/leader for such teams?
This paper describes diversity and inclusion in its broadest sense, and its benefits and challenges within the context of the oil and gas industry, in particular with regard to Petroleum Engineering and subsurface teams. A number of common and practical industry situations are considered, and the merits of further opportunities are discussed. The fundamental actions and behaviours that help oil and gas companies promote and establish more diverse and inclusive teams and cultures, in order to deliver outstanding results, are examined.
As the shale development activity in the Permian continues to be strong and oil prices recover, increasing numbers of infill child wells are being drilled as operators want to improve recovery from each section and continue to meet their production targets. However, production data suggests that both parent and child wells suffer from production losses if they are located too close to one another.
The cube model concept, which is also referred to as supersize fracturing, was first introduced about two years ago and has been piloted in the Permian Basin. In a cube model, multiple wells, usually more than 30 horizontal wells with five to six wells in each different horizontal layer, are drilled and completed in the same section. Operators produce those wells simultaneously with the objective of mitigating the parent-child effect of unconventional reservoirs.
Nevertheless, with all wells producing at the same time and competing for production from the first day, will this benefit ultimate recovery? This question was investigated through comprehensive fracture and reservoir modeling and simulation. A reservoir dataset for the Spraberry Formation in the Permian Basin was used to build a hydraulic fracture and reservoir simulation model.
Different field development strategies were studied. Models representing a traditional parent-child scenario with five parent wells completed and produced one year before four infill child wells and a traditional parent-child scenario with five parent wells completed and produced five years before four infill child wells are compared. In these cases, a geomechanical finite-element model (FEM) was used to quantify the changes to the magnitude and azimuth of the in situ stresses from the various reservoir depletion scenarios. Next, a cube model with nine horizontal wells completed and produced simultaneously was analyzed. These three scenarios were expanded to include 19 horizontal wells with the same methodology.
This study aims to help operators in the Permian Basin, as well as in other unconventional reservoirs to understand how different field development strategies affect ultimate hydrocarbon recovery and net present value.