MH 370 disappearances on 8 March 2014 while flying from Kuala Lumpur International Airport in Malaysia to Beijing Capital International Airport in China is a real testing ground for National Search and Rescue (SAR) in Malaysia environment. Based on this incident, Malaysia oil & gas started to measure the preparedness of industry in facing similar situation with helicopter used for offshore workers mobilisation. In ensuring higher percentage of probability for survivors' to be successfully rescued by including the optimization of'golden hours', seven factors were measured during the SAR Exercise: a.
Sparrows Group named Matt Corbin as its regional operations director for the UK and Europe. Corbin has more than 20 years of industry experience, having held several leadership positions including UK managing director for the subsea division at Aker and UK regional manager at GE Oil & Gas. Most recently he was the supply chain consultant for the Oil and Gas Authority, the UK government's regulatory body, and contributed to Oil & Gas UK's Efficiency Task Force. He holds a bachelor's degree in mechanical engineering from Brunel University.
The old adage that ‘You can’t manage, what you can’t measure’ is holds good today as well. Many Organizations are establishing SH&E management systems in line with international management systems to measure the performance, protect an organization’s assets, people and the environment. The use of performance standards, commonly known as metrics, has become an integral requirement of the SH&E management system aligning with main organizational goals. Lagging metrics such as accident, frequency & severity rates have dominated almost all Organizations as the key indicators of their SH&E performance since decades. These numbers and figures have been in wide use to represent an organization’s image in the SH&E arena. However, the advanced SH&E management systems have started to expand their attention to a few other leading indicators as well. This shift from an age old practice is primarily to be more proactive and effectively predict future SH&E issues. Leading and lagging metrics are used to verify whether the products, processes and systems that have been implemented to prevent or control losses that can impact the customers of the organization are effective and functioning as designed.
SH&E metrics must be integrated into all levels of the organization if SH&E aspects are to become an integral part of the business plan and operations. In many respects that management extends not only to the performance of the business in a safer way with the lack of accidents but also on the ‘productivity’ of the SH&E professionals employed by the Organizations. This requires SH&E professionals to integrate themselves at the highest levels of the Organizations to ensure that the SH&E initiatives are recognized and valued. Since each organization has various internal and external stakeholders, such as employees, visitors, contractors, shareholders, regulators, the public, suppliers, customers etc., the use of organization specific performance measurement metrics aligning with their organizational main goals will be specific depending on the nature of their organization. The need to develop and implement a comprehensive SH&E metrics program aligning with the organizational goals is a critical part of creating confidence in management and soliciting support for the programs. With the increasing move towards globalization, SH&E Professionals encounter a challenge of understanding of organization / country specific SH&E measurement metrics as they move from each type of industry across several countries.
"He who loves wine and oil Majority of 2015's $100B decline will be in the US in the Shale Plays
Purpose: This paper analyses Skill requirements of Oil & Gas Industry in India in the coming years. Further, it takes a look at the Talent Crisis looming large in Oil & Gas Industries in India and measures being taken to counter the challenges arising out of pending wave of retirements and competitive recruitment pressures from other industries. The paper also analyzes Female workforce participation in the Indian Oil & Gas Industry and a broad comparison is done with other Industries. The key issues related to women employees and mitigation strategies for the same are studied for other Industries and compared with that of Oil & Gas Industry.
Research Methodology: We studied 7-10 companies in various industries by approaching the HR Team Members of the said companies with a questionnaire to identify the various practices, degree of advancement of the practices and impact achieved. Overall industry ‘Advancement Level’ and Oil & Gas Industry ‘Advancement Level’ was arrived at for Practices targeted at attracting, retaining and developing women employees. We also assessed attractiveness of ‘Oil & Gas Industry’ amongst female students through a survey.
Findings: With continued shortage of skill, attracting women employees to this industry is a business imperative. Economic success and competitive advantage may depend on attracting and retaining women employees. Certain other Industries have achieved a significant edge over Oil & Gas Industry in terms of attracting and retaining women employees. Oil & Gas Industry needs to work on ‘Improving its Brand Perception’, ‘Reaching Out to Women Talent’ and implementing practices to facilitate women employees in achieving ‘Work-life Balance’ and ‘Career Growth’.
The paper gives a detailed view on areas of improvement for Oil & Gas Companies in India to be able to attract & retain women employees in this era of ‘War for Talent’.
Offshore wind turbines are becoming one of the main sources of renewable energy in Western Europe. The majority of these wind turbines are supported by piled foundations, which have been used successfully for offshore Oil & Gas platforms. One of the key issues in the transfer of offshore Oil & Gas experience to offshore wind energy is the use of design standards that were developed specifically for offshore Oil & Gas platforms. Moreover, certain European countries require the use of national standards that reflect longstanding onshore design practice. Important differences exist between the methods for deriving extreme loads and the calculation procedures for deriving foundation capacity. The prescribed partial factors for use in load resistance factor design (LRFD) are not always consistent.
This paper demonstrates how combinations of different design standards can lead to significant differences in the reliability of piled foundations for offshore wind turbines. A reliability-based framework, taking into account the uncertainty in loads and pile capacities, is presented here as a basis for assessing wind turbine foundation reliability. For an example tripod structure in the North Sea, the annual probability of failure achieved with different design standards ranges over more than two orders of magnitude from 2x10-6 to 3x10-4. For the BSH standard, the reliability achieved for this tripod foundation exceeds that required for offshore Oil & Gas platforms in Eurpoe.
This paper highlights the need to need harmonize design standards for offshore wind turbines in Europe and elsewhere. This type of analysis could be used to establish the foundation-related risk exposure for a single structure and for an entire offshore wind park in order to provide for renewable energy facilities that effectively balance risks and costs. Wind energy can only become a viable energy source when safe and cost-effective designs are used.
CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
CO2 is the dominant anthropogenic greenhouse gas that is believed to be driving global warming and climate change. Carbon capture and storage (CCS) is a technology that may contribute to reduction in CO2 emissions. However, CO2 capture from flue gas sources with current technology is CAPEX and energy intensive, so that the cost of CO2 abatement with CCS is high.
At the same time CO2 is an effective miscible flooding agent for EOR. Capturing CO2 from industrial sources for use in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future. Firstly, by adding value through additional oil recovery and field life extension, which can offset part of the cost of CO2 capture, and secondly, by providing long term secure storage after EOR operations have been completed.
Moving from onshore to offshore
Existing CO2 EOR projects are all onshore, with the majority of projects supplied with CO2 from natural subsurface sources. A minority of projects is based on captured CO2 from anthropogenic sources, with the largest being the Weyburn CO2 EOR and storage project, using CO2 captured from a coal gasification plant . Operating offshore CO2 injection has so far been restricted to storage of CO2 produced from gas processing plants, with the Sleipner  and Snøhvit  projects each injecting around one million tpa of CO2. Maximising value from disposal of CO2, (whether this is from low cost sources such as gas processing plants or more expensive flue gas capture) requires suitable EOR target fields, and in regions such as Europe and the Far East, large scale operations require moving CO2 EOR offshore into the major hydrocarbon basins.
Connacher's first oil sands project, the Pod One facility at Great Divide, has been operational since 2007. The successful SAGD project has produced approximately 7 million barrels of bitumen. During the past three and a half years, the impacts of certain predicted reservoir challenges and opportunities have become apparent.
While the quality of the oil sands in this first phase of Pod One is generally good, Pad 101 South in particular has geological zones that affect SAGD operation. This includes a bitumen lean zone, and a gas cap overlying the main bitumen channel/s. Early field results matched with detailed simulations have shown positive results in maximizing well pair production. For the purposes of this paper a lean bitumen zone differs from an aquifer in two ways. The lean zone is not charged, and is limited in size. The operation is also complicated by the fact the gas bearing zone has been depleted through earlier production.
Connacher's operating practice at Great Divide attempts to achieve a pressure balance between the 3 zones (rich oil sands, lean zone, gas cap) to reduce steam loss and maximize production rates. Reducing the pressure encourages steam chamber development growth horizontally and ensures that steam contacts the highly saturated bitumen areas. How this is achieved with the highest positive impact on well productivity is illustrated with operational data and analysis including the results of simulations that recommended the optimum operating strategies.
The paper presents an Equation-of-State (EOS) modeling work carried out for a Middle East reservoir fluid for which gas injection was considered for increasing ultimate recovery. The aim of the work was to develop an EOS model that would accurately reproduce the phase behavior in a reservoir on injection of either a hydrocarbon gas (mix of gas condensate and associated rich gas) or a CO2 rich gas. A single EOS model was developed, which provided a good match of data for both injection gases. This EOS model enables compositional reservoir simulation studies to be carried out comparing and contrasting the recovery from the field with each of the two injection gases.
Extensive PVT data was available and to be matched by a 9-component 'lumped' EOS model. Available data included classical PVT data as well as gas injection (EOR) data including solubility swelling, equilibrium contact and slim tube tests. A major challenge was to develop a model which, in addition to classical PVT data, which can easily be regressed to, also matched slim tube minimum miscibility pressures (MMPs). A multi-component tie-line method was used considering combined vaporizing/condensing drives, and the tie-line MMP was afterwards verified using a cell-to-cell simulator.
Depth gradient simulations indicated that the transition from liquid-like to vapor-like properties in the reservoir did not take place through a sharp gas-oil contact (GOC), but happened continuously in a 'transition zone'. An EOS model neglecting such 'transition zones' or simulating a sharp gas-oil contact may lead to severe misinterpretations in reservoir simulations. A segregation model based on irreversible thermodynamics was used to investigate the influence of an observed vertical temperature gradient on the compositional variation with depth.