Business Risk Management Applied to Offshore Pipeline Field Development

2010 ◽  
Author(s):  
Lihua Gan
Keyword(s):  
Risk Management ◽  
Oil And Gas ◽  
Business Risk ◽  
Offshore Pipelines ◽  
Field Development ◽  
Class Project ◽  
Offshore Pipeline ◽  
World Class ◽  
The Cost ◽  
Production Facilities

A world class project must have a disciplined business risk management. As a good project manager, he should manage project risk successfully. Through business risk management, he can identify risk of the project, find the cause of all business risks, then define the influence of all risks. He can take measures to avoid, transfer, and mitigate the risk. A field development includes production facilities, risers and pipelines and subsea wells, in which the pipelines and risers connect the subsea wells and production facilities to transfer oil and gas. The cost of offshore pipelines and risers is major. In the following we shall take offshore pipeline and riser as a case study to practice the principal of business risk management step by step. It has been demonstrated that the method may be applied to maximize the returning for the stakeholders in an offshore field development. However, it is suggested to accumulate and update the data bases required for an accurate statistical evaluation.

The Selection and Optimum Well Testing Practices to Achieve Zero Flaring & Venting in Malaysian Water for a Petronas Field Development

2021 ◽  
Author(s):  
Adhi Naharindra ◽  
Zalina Ali ◽  
Nik Fazril Ain Sapi’an ◽  
Latief Riyanto ◽  
Fuziana Tusimin ◽  
...  
Keyword(s):  
Environmental Impact ◽  
Oil And Gas ◽  
Oil Field ◽  
Testing System ◽  
Well Testing ◽  
Well Test ◽  
Flow Lines ◽  
Field Development ◽  
Well Completion ◽  
Production Facilities

Abstract Increased HSE concerns and global economic efficiency from well testing activities especially on its environmental impact have left several oil and gas industries’ facing critical challenges to develop and monetize oil reserves. Some of these challenges include handling well effluents from well test unloading operations after well completion with high contaminants such as H2S and CO2 which will exacerbate environmental impact to safety, pollution, and oil spill risks. In addition, mitigation to environmental impact will be constrained to limited deck space and topside loads for offshore wellhead facilities and eventually restricts the footprint of well test unloading equipment. The scope of the paper is to examine the evolution of well deliverability testing from conventional well test facilities’ flaring practices to contemporary smokeless and zero flaring operations applied in a giant sand stones oil field in Malaysian water, which is surrounded by a world class environmentally protected marine and coastal ecosystem. The zero-flaring approach allows a demonstration of the safety & emission reduction, cost saving, technical viability, and economic benefits over traditional flaring techniques for 20 to 30 well testing during the life of field. Previous wells clean up method require flaring of oil and gas before the production facilities and flow lines were operational.commissioned. The application of environment friendly well testing system using the completed flow lines and production facilities enable zero-flaring option to be technically and economically viable. Zero-flaring well testing system provides several attractive benefits, with potential reduction in flaring equivalent of ±1000 barrels of oil, pollution avoidance, 40 - 50% schedule reduction and over 40% reduction in total project costs for the field development..

Optimizing Production Facilities Using a Transient Multiphase Flow Simulator

2019 ◽  
Author(s):  
Abdulaziz S. Al-Qasim ◽  
Fahad Almudairis ◽  
Abdulrahman Bin Omar ◽  
Abdullatif Omair
Keyword(s):  
Multiphase Flow ◽  
Oil And Gas ◽  
Gas Production ◽  
Oil Field ◽  
Flow Assurance ◽  
Field Development ◽  
Wide Range ◽  
Flow Simulator ◽  
Transient Multiphase Flow ◽  
Production Facilities

Abstract This paper discusses a method for optimizing production facilities design for onshore/offshore wells during new field development. Optimizing the development of new oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. It involves the use of a transient multiphase flow simulator (TMFS) for designing new oil and gas production systems to determine the feasibility of its economic development. A synthetic offshore oil field that covers a wide range of subsurface and surface facility data is considered in this paper. 32 wells and two reservoirs are considered to evaluate the effect of varying sizes of tubing, wellhead choke, flowline, riser, and transport line. A detailed investigation of the scenario of emergency shutdowns to study its effect on the system is performed using TMFS. Other scenarios are also evaluated such as startup, depressurization, pigging, wax deposition, and hydrate formation. This paper provides a method to minimize the cost by selecting the optimum pipelines sizes and diameters, and investigating the requirements of insulation, risk of pipeline corrosions and other related flow assurance parameters. Different facility design scenarios are considered using TMFS tool to achieve operational flexibility and eliminate associated risks. Pressure and temperature conditions are evaluated under several parametric scenarios to determine the best dimensions of the production system. This paper will also provide insight into factors affecting the flow assurance of oil and gas reservoirs.

scholarly journals Value Change in Oil and Gas Production: III a Time to Buy, a Time to Sell, a Time to Decide

2002 ◽  
Vol 20 (4) ◽  
pp. 289-298 ◽  
Author(s):  
I. Lerche ◽  
S. Noeth
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Production Economics ◽  
Rational Decision ◽  
Value Change ◽  
Oil And Gas Production ◽  
Field Development ◽  
New Information ◽  
The Cost

Deciding whether to buy new information to potentially improve the residual reserves of a producing oilfield, and what price to pay for the information, which may or may not actually improve the reserves picture, is a problem of some concern to field development and production economics. Here we show how the worth of obtaining new information depends not only on the reserves produced to date but also on the residual reserves still to be produced, on the probability that purchase of new information will indeed improve the known reserves, on the value estimated to be produced by the acquisition, and on the cost of the acquisition. There are also dependencies on production and lifting costs but these are not considered in detail here. The timing of a decision whether to acquire new data and how much to pay for it, are illustrated using total profitable gains made to date as a proxy for time. Two simple examples are worked through in detail so that one can see when the uncertainty of possible gains from newly acquired information are sufficient, relative to costs and the worth of residual reserves still to be produced, to allow management to make an informed and rational decision on whether to acquire and when to acquire new information in respect of the life of the field without such acquisition.

scholarly journals THE ISSUES OF FIRE AND BLOWOUT SAFETY OIL AND GAS FIELDS

2015 ◽  
pp. 122-125
Author(s):  
Yu. . Akulov ◽  
V. A. Dolgushin
Keyword(s):  
Western Siberia ◽  
Oil And Gas ◽  
Preventive Measures ◽  
Field Development ◽  
Far North ◽  
Oil And Gas Fields ◽  
Safety Production ◽  
Construction Operation ◽  
Gas Fields ◽  
Production Facilities

The problem of fire and blowout safety during the construction, operation and repair of wells during field development of oil and gas in the far north of Western Siberia. To ensure the safety production facilities offer specific preventive measures, which are aimed at the realization of the efforts of existing fire and blowout units.

Late life management of onshore and offshore pipelines

2015 ◽  
Vol 55 (2) ◽  
pp. 414
Author(s):  
Brian Humphreys ◽  
Wacek Lipski
Keyword(s):  
Oil And Gas ◽  
Life Review ◽  
Remaining Life ◽  
Offshore Pipelines ◽  
Field Development ◽  
Design Life ◽  
Inspection And Maintenance ◽  
1960S And 1970S ◽  
The 1960S ◽  
Opening Up

The Australian oil and gas boom of the 1960s and 1970s lead to production commencing in the Gippsland, Surat, Cooper and Carnarvon basins and so many pipeline assets around Australia are approaching operating lives of 40-50 years and the end of their design lives. With unconventional field development and the Australian gas markets opening up to international customers through LNG, there will be an increasing requirement to extend the life of pipelines while maintaining safety and integrity. The management of pipeline assets late in their design life is a challenge for operators both onshore and offshore, with pipelines requiring higher levels of inspection and maintenance, while revenues can be fixed or regulated for downstream assets or potentially declining for upstream assets. To operate pipelines beyond their specified design life, there are requirements that must be fulfilled—for offshore, a design re-qualification in accordance with DNV-OS-F101 and for onshore, a remaining life review in accordance with AS2885.3. In addition, for onshore pipelines, AS2885.3 requires the remaining life review process to be undertaken every 10 years, rather than just at the end of the design life. This extended abstract discusses the requirements of the DNV-OS-F101 and AS2885.3 and the approaches required to meet these requirements. It also discusses key lessons that have been learned and makes recommendations to pipeline operators preparing for end-of-design-life reviews and executing them as cost effectively as possible.

Reducing Cycle Time to First Oil for Deepwater Field Developments

2005 ◽  
Author(s):  
Beverley F. Ronalds
Keyword(s):  
Cycle Time ◽  
Fast Track ◽  
Net Present Value ◽  
Oil And Gas ◽  
Economic Returns ◽  
Present Value ◽  
Field Development ◽  
Wide Range ◽  
Primary Determinant ◽  
The Cost

The cycle time to first production is a primary determinant of the net present value (NPV) of an oil and gas asset. The cost, complexity and risk inherent in deepwater field developments, combined with the relative lack of experience in their execution, often encourages engineers to proceed cautiously in field development. However, a successful fast-track development schedule from discovery to first oil may bring significantly better economic returns. This paper investigates the key parameters influencing cycle time for different facility types, and outlines a wide range of measures that may be adopted to accelerate the time to first production.

Assessment of the impact of ice gouging on the Arctic marine pipeline systems

2021 ◽  
pp. 284-292
Author(s):  
Ирина Георгиевна Силина ◽  
Вадим Андреевич Иванов ◽  
Сергей Валерьевич Знаменщиков
Keyword(s):  
Oil And Gas ◽  
Systems Design ◽  
The Arctic ◽  
Burial Depth ◽  
Offshore Pipelines ◽  
Offshore Pipeline ◽  
Distribution Features ◽  
Pipeline Systems ◽  
Subsea Pipelines ◽  
The Impact

Для исследования методик оценки влияния ледовой экзарации на подводные трубопроводы проанализирована отечественная и зарубежная нормативно-техническая база в области проектирования, строительства и эксплуатации морских трубопроводных систем, подробно рассмотрены общие подходы к решению данного вопроса. Систематизирован опыт строительства и эксплуатации трубопроводов в условиях замерзающих акваторий, представлены способы их защиты от повреждений в результате дрейфа ледовых образований. Дана оценка характера формирования и особенностей распределения ледово-экзарационных форм по глубине акваторий. Показано, что существующая методология оценки воздействия ледовой экзарации на морские трубопроводы не позволяет в полной мере учесть льдогрунтовое взаимодействие. Установлена целесообразность разработки критериев для определения минимальной безопасной глубины заложения подводных трубопроводов в районах с дрейфующими льдами. Обозначены направления дальнейших исследований механизмов ледового выпахивания, деформаций прилежащего к трубе грунтового массива и поведения заглубленного трубопровода. Полученные результаты позволят дополнить существующую методологию учета воздействия ледовой экзарации на морские трубопроводы, прокладываемые в замерзающих акваториях, с целью обеспечения их безопасности и надежности. To consider the methods of assessing the impact of ice gouging phenomenon on subsea oil and gas pipelines, the authors analyzed Russian and foreign codes and standards in the field of offshore pipeline systems design, construction and operation, and also considered in detail scientific approaches to investigate this issue. Within the framework of the analysis of peculiarities of offshore pipelines operation in areas with ice gouging, systematization of experience gained from pipeline systems operation in freezing waters was carried out, and methods of pipeline protection from damages caused by drifting ice formations were considered. The assessment of ice induced gouges formation and distribution features is performed. It is shown that the assessment methods presented in current codes and standards to determine the ice gouging impact on marine pipelines do not allow to directly take into account the ice-soil interaction. The feasibility of developing criteria for determining the minimum required burial depth for subsea pipelines in areas with ice gouging is determined. The directions of further research to ensure safe and failure-free operation of subsea pipeline systems in freezing water areas are presented.

Main approaches to estimating the cost of shareholder equity of oil and gas producers

2020 ◽  
Vol 26 (3) ◽  
pp. 685-697
Author(s):  
O.V. Shimko
Keyword(s):  
Oil And Gas ◽  
Oil Prices ◽  
Minimum Cost ◽  
Free Cash Flow ◽  
Annual Reports ◽  
Comparative Approach ◽  
Economic Activities ◽  
Advantages And Disadvantages ◽  
Oil And Gas Producers ◽  
The Cost

Subject. The study analyzes generally accepted approaches to assessing the value of companies on the basis of financial statement data of ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, Gazprom, Rosneft, LUKOIL, and others, for 1999—2018. Objectives. The aim is to determine the specifics of using the methods of cost, DFC, and comparative approaches to assessing the value of share capital of oil and gas companies. Methods. The study employs methods of statistical analysis and generalization of materials of scientific articles and official annual reports on the results of financial and economic activities of the largest public oil and gas corporations. Results. Based on the results of a comprehensive analysis, I identified advantages and disadvantages of standard approaches to assessing the value of oil and gas producers. Conclusions. The paper describes pros and cons of the said approaches. For instance, the cost approach is acceptable for assessing the minimum cost of small companies in the industry. The DFC-based approach complicates the reliability of medium-term forecasts for oil prices due to fluctuations in oil prices inherent in the industry, on which the net profit and free cash flow of companies depend to a large extent. The comparative approach enables to quickly determine the range of possible value of the corporation based on transactions data and current market situation.

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