Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156098, ’Deal With Startup and Commissioning Threats and Challenges at an Early Stage of the Project for a Successful Handover and Project Completion,’ by M. Al-Bidaiwi, SPE, M.S. Beg, SPE, and K.V. Sivakumar, Qatar Petroleum, prepared for the 2012 SPE International Production and Operations Conference and Exhibition, Doha, 14-16 May. The paper has not been peer reviewed. Qatar Petroleum (QP) involved its operations team from the early stages in two of its major projects implemented in the Dukhan field and experienced successful implementation of the projects by meeting the project schedule and cost, smoothly handing over the facility, and achieving the intended objectives with adequate safety and operational flexibility. QP-Dukhan’s operations team played a major role in providing clarity and coherence of project objectives among various divisions and geographically diverse contractors. Introduction QP executed two major projects in the Dukhan field. Operations management felt the need to involve the operations team throughout the project. Accordingly, the Dukhan operations department deployed a team to coordinate with the project management team (PMT) and contractors. The contributions made by the operations team were immense and resulted in successful implementation of the projects, a smooth handover, and achievement of the intended objectives. Organizational Structure for Project Implementation Dukhan facilities come under the Operations Directorate, whose primary functions are manufacturing and production operation and distribution. Projects are handled by the Technical Directorate. Project proposals are initiated by operations (asset holder) on the basis of defined objectives, and they are sent to the Technical Services department. The Technical Services department processes the proposal and uses a contractor to conduct a feasibility study and concept optimization. Further phases of the project, such as the front-end engineering design (FEED) and engineering, procurement, installation, and commissioning (EPIC), are handled by different departments within the Technical Directorate through external contractors. After commissioning and startup, the new facility is handed over to operations (Fig. 1). Operation’s Role in Project Implementation The operations team was involved in the feasibility study and concept optimization. All technical deliverables from the feasibility study contractor were reviewed, and the operations team provided comments. This was done in addition to a document review by engineers in the Technical Services department. Review comments from the operations team were forwarded to engineers in Technical Services; these comments were reviewed further and forwarded to the contractor. Thus, the operations team was involved in the feasibility study and concept optimization of the project. The operations team was involved continuously throughout the project cycle. During the FEED and EPIC phases, the operations team was involved in the review of all technical deliverables from the contractors. Furthermore, the operations team was invited to participate in design review meetings, discussions with licensors and contractors, process flow diagram review, risk assessment, hazard identification study, safety integrity level assessment study, model reviews, factory acceptance test, site acceptance test, and all other technical meetings, along with construction supervision and all activities related to precommissioning, commissioning, and startup.
Digital standards Late June in Houston, Texas, senior executives from the Standards Leadership Council’s (SLC) nine member organizations hosted a forum, whose goal was to encourage collaboration on open digital standards for the benefit of the upstream oil and gas industry. More than 125 industry representatives attended the all-day event. Formed in February 2012, the SLC’s mission is to avoid duplication in oil and gas industry electronic standards development projects and to address mutual challenges, such as determining business value metrics for standards adoption, enhancing the benefits members receive from the various oil and gas digital standards, and maintaining financial sustainability of standards organizations. Derek Mathieson, president of western hemisphere operations at Baker Hughes, delivered the keynote address. He became involved with the digital oil field in the mid-’90s. The problems then, according to Mathieson, were the result of having to deal with 50 years’ worth of infrastructure. “You would have thought almost all of that would have gone away by now,” he said. “But the same challenges exist today.” Looking ahead, Mathieson observed that fascinating things are going on in relation to learning and connectivity—what he referred to as “the ‘wikification’ of our business” to facilitate learning. Heavily influenced by social media and reliance on collaboration, the new generation of professionals in the petroleum industry appears to learn in ways that are different from “traditional” ways of learning. He said he believes, therefore, the challenge now is how to “take away the pain of major project implementation.” This leads to the need for increased industry collaboration for electronic standards, said Mathieson, who encouraged forum attendees to participate in the development process. Duncan Junor, vice president for Halliburton and the Energistics’ board chair, formally closed the forum. “It was a sold-out event,” he said, “which speaks volumes to the dedication and passion of this industry to work together to adopt and implement standards.” “Just to have all nine standards organizations in the same room,” he continued, “is a huge accomplishment.”
- Europe (1.00)
- Asia (1.00)
- North America > United States > Texas > Harris County > Houston (0.54)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151186, ’Upgrading the Real-Time Drilling-Optimization Culture in Brazil's Challenging Deepwater Operations: The Utilization of a Remote and Rigsite Multidisciplinary Collaborative Concept,’ by Augusto Borella Hougaz, Danilo S. Gozzi, Isao Fujishima, and Klaus L. Vello, Petrobras, and Sandro Alves, Ian Thomson, Raul Krasuk, SPE, and Frank Buzzerio, Baker Hughes, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed. In Brazil, deepwater well-construction activity has increased significantly since the first major presalt discovery in the Santos basin in 2006. The creation of a multidisciplinary drilling-optimization group, integrated with the operator’s drilling team in 2008, and the introduction of a highly specialized downhole-drilling-dynamics measurement-while-drilling (MWD) tool changed the drilling-optimization concept in Brazil. This new optimization concept pioneered the remote (off-the-rig) downhole drilling-parameters surveillance in deepwater operations. Introduction A novel real-time optimization drilling service was implemented in 2008 with the major deepwater operator in Brazil in the Santos basin. Throughout the implementation and execution of the real-time optimization service, the importance of not only knowing where (wellbore placement) and what (formation evaluation) you are drilling but also how you are drilling, which is mainly driven by the integration between operator and service company, became apparent. After 3 years, it was clearly observed that the higher the integration between service company and operator was in a proactive and collaborative environment, the higher the drilling performance was. Today, in the deepwater Santos basin presalt environment, the real-time optimization drilling service is already part of the drilling program in almost every well, from the top hole section to the reservoir section. Real-Time Drilling-Optimization Team In 2008, to answer the “how” questions in the Santos basin, a new culture of real-time optimization arose with the concept of a multidisciplinary optimization team from the service company acting in collaboration with the major operator in Brazil in an integrated manner to achieve superior performance. To accomplish effective remote and rigsite real-time drilling optimization, it is important to use a highly specialized downhole drilling-dynamics MWD tool that records and transmits real-time dynamics data (e.g., stick/slip, lateral vibration, whirl, and axial vibration) and downhole drilling parameters (e.g., weight on bit, torque, revolutions per minute, and bending moment), which allows for a better judgment of the down-hole conditions while drilling and better support for adjusting the surface drilling parameters to optimize operations, in a continuous feedback cycle (Fig. 1).
- South America > Brazil > Brazil > South Atlantic Ocean (0.98)
- North America > United States > California > San Diego County > San Diego (0.25)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 152353, ’Developing Social-Performance Indicators and Maintaining Corporate Social Responsibility in a Developing Country During Construction and Operation of an LNG Plant,’ by Jeanette Rascher and AbdulSalam Al-Shamsi, Yemen LNG Company, prepared for the 2012 SPE Middle East Health, Safety, Security, and Environment Conference and Exhibition, Abu Dhabi, 2-4 April. The paper has not been peer reviewed. Maintaining corporate social responsibility is vital in securing a stable operating environment. The selection of social key performance indicators is crucial to promote long-term strategic goals, set targets, track performance, proactively identify triggers for change, and drive future improvement in performance. A range of indicators was developed to support the ongoing monitoring and evaluation of the company’s social-management plan, including community investment projects, livelihood restoration, reinstatement, and the effectiveness of community engagement within the project area. Introduction Indicators are used to track process and progress, and to determine whether the social component is making a positive difference (maximizing beneficial project effects) or minimizing risk (mitigating or reducing the negative effects of project activities as far as practicable). A monitoring and evaluation system was established as a tool to ensure that the company would achieve the goals and objectives set in its social-management plan and that the project design and criteria were followed, implementation effects occurred as predicted, emerging or unanticipated issues and projects were managed efficiently and effectively, lender and social-performance review requirements were complied with, international best practice was followed, national legislation was adhered to, and human development and capacity building occurred. Project Background A project was launched in August 2005 to design, construct, and operate a liquefied-natural-gas (LNG) plant on the southern coastline of Yemen, with an associated land pipeline to market and export the LNG, as shown in Fig. 1. Primary stake-holders included project-affected people (PAP), local and central government and governmental agencies involved with and exposed to project activities, and project employees. In terms of the LNG project, PAP are defined as communities, households, and individuals who live in close proximity to the project site. There were 22 clearly defined villages within a 5-km corridor on either side of the pipeline right of way and seven in the vicinity of the Balhaf liquefaction plant. Within each of these 29 villages (with their sub-villages), there are highly complex and potentially volatile household and tribal structures based on social, cultural, and religious norms founded in the community over many generations and which determine authority, respect, and status within the community. It is common for many families, relatives, and individuals to reside within a single household in a single village or community. Secondary stakeholders included those who have links (e.g., technical expertise) with primary stakeholders. Secondary stakeholders include nongovernmental organizations, various intermediary or representative organizations, and technical and professional bodies, often representing public interests.
- Asia > Middle East > Yemen (0.56)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.25)
- Social Sector (1.00)
- Energy > Oil & Gas > Midstream (1.00)
Management Compare the approaches of the top 10 operating companies around the world to tackling the asset integrity challenge and you will find many similarities. Whether in the models used to identify risks or the approaches used to manage them, the industry thinking has evolved to a point at which most agree on the fundamental elements of how to approach integrity management. Look closer and you might find some more commonalities. The reasons asset integrity management strategies often fail to achieve the expected results are also often the same from operator to operator. So what are these reasons, and how can you ensure you are building them into your implementation strategy to ensure that you do not repeat them? There are 10 reasons why integrity management implementations often fail. Trying to tackle integrity in isolation. Perhaps the most common reason asset integrity strategies fail is integrity specialists trying to achieve integrity in isolation. Integrity is not a subject that thrives in a silo—it requires the entire business to be aware, on board, and supporting of a unified effort. Staffers need to know how integrity affects their daily job, and they need to be encouraged, cajoled, instructed, and motivated to ensure that they are working together. Different groups have different goals, but not caring about others’ goals and complaining about having to do others’ work demonstrates a silo mentality. If that type of silo mentality exists, there will be problems in implementing integrity management. Losing sight of process, people, and plant. It may seem obvious, but an asset integrity plan is an extremely complex undertaking with many moving parts and even more stakeholders involved in its successful execution. Recognizing that there are many reasons why asset integrity implementations do not achieve the results expected of them is an important starting point. Problems are not confined to one particular area of an integrity implementation and can just as easily emerge in either the process, the people, or the plant components that make up an integrated integrity management program. Focus too narrowly on one area and you can be sure problems will emerge elsewhere. The key to implementation is the effective working together of these three components and ensuring that checks and balances exist at every stage.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150066, ’Intelligent-Field-Infrastructure Adoption: Approach and Best Practices,’ by Soloman Almadi, SPE, and Tofig Al-Dhubaib, SPE, Saudi Aramco, prepared for the 2012 SPE Intelligent Energy International, Utrecht, the Netherlands, 27-29 March. The paper has not been peer reviewed. The drive toward implementing an intelligent-field infrastructure (IFI) is a continuous aim for operators. It requires the correct balance between technology, business drivers, and evolving implementation requirements. Successful implementation relies on a robust real-time field-to-desktop data-acquisition and -delivery system designed with clearly defined data-acquisition requirements. The challenge in achieving such an objective is made more difficult by the variables that must be considered when addressing an IFI integrated solution. Saudi Aramco’s experience and methodology of developing an IFI field-to-desktop data-acquisition and -delivery infrastructure for new fields is presented. Introduction Typically, IFI deployment is carried out through different phases and time lines. The process begins after establishing an understanding of the reservoir, completing field-development-plan objectives, defining end-user requirements, and selecting the hardware and software to meet the intended objectives. The result is an integrated field-to-desktop data-acquisition and -delivery system (Fig. 1). The essential steps include, but are not limited to, establishing existing-technology base-lines, defining funding, and formulating optimal data flow. Then, the construction and end-to-end integrated testing steps begin, which may include sub-steps that affect the final infrastructure performance outcomes. Adopting an IFI requires a holistic end-to-end de-sign approach. Methodology This approach involves steps of defining and planning data requirements, designing, and capacity planning of each of the IFI components involved in data acquisition and delivery. Also, end-to-end integration, reliability testing, and key-performance-indicator (KPI) definition are important. Some of these critical steps are carried out in sequence, while others are managed concurrently. Subject-matter expertise and full under-standing of the holistic workflows of the operation are integral to the process. Also, a survey of existing academic and industrial best practices is an essential continuous feed. Planning. The planning stage begins after completing a comprehensive field-development plan aimed at optimizing development cost and maximizing the production-plateau duration and the recovery. The field-development plan dictates many strategic decisions (e.g., primary depletion, secondary immiscible flooding, and tertiary-recovery schemes), tactical decisions [e.g., well spacing and orientation, well type (vertical, horizontal, maximum-reservoir contact), and well completions using smart tools], and operational decisions (e.g., pressure-maintenance levels and gas-recycling fraction). Thus, the number, type, and location of the wells and their required intelligent-field technologies are determined at this point along with the field-production-operation and reservoir-management strategies.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.96)
Guest editorial The upstream oil and gas industry is known for its massive and complex projects around the globe. Many projects are very profitable, but this is more a result of high oil and gas prices that have prevailed in the past decade rather than to good project management. There is in fact a tendency for E&P projects to underperform—managements overspend, deliver late, and underproduce compared with the original targets. Worldwide experience shows that this is predominantly because of poor project definition, poor uncertainty management, and, hence, poor decisions. No doubt, exploration and production (E&P) projects are difficult to manage because they require coordinating and executing a vast array of activities at various levels of detail and complexity, such as technical evaluations, technology implementation, risk and uncertainty management, health and safety, economic evaluation, finance, contracting and procurement, governance, decision making, resourcing, planning and scheduling, stakeholder management, and societal responsibility. All the activities need to be aligned and integrated, which means that the people working the project and the stakeholders need to be aligned across discipline, functional (technical, economics, commercial, legal, and support functions), and company boundaries (governments, partners, and the public). This is a challenge to say the least. The management of E&P projects is becoming even more challenging because the industry is faced with producing more difficult hydrocarbons to meet increasing global energy demand. Production is not only coming in more remote areas, in deep water, and in harsh conditions, but also in a more complex geology, from heavy oil to tight and sour gas, and from unconventionals. In addition, projects tend to be subject to stricter regulations and higher standards in order to prevent accidents or to contain the health, safety, and environmental consequences. All these require a greater understanding of the subsurface, the application of advanced technologies, compliance to stricter regulations, more investments, and more (experienced) people. Some E&P Learnings The following E&P project learning examples are probably valid, to a lesser or greater extent, for any industry sector involved in complex, high capital spending business opportunities and projects. A common complaint is that organizations tend to dive in without properly considering what the opportunity is about. They do not look at a wide enough variety of scenarios: Projects carry optimistic base case assumptions and/or narrow ranges in the outcome of the key uncertainties (e.g., reservoir properties or circumstances with an uncertain outcome could change the field development concept). Also the project management may not consider a sufficiently wide range of concepts and sometimes specific field development alternatives are overlooked. Project economics often do not sufficiently reflect the specific risks and uncertainties. The cost estimates are not transparent or appear to be largely based on historical costs models that do not take into account future projections related to the buoyant/overheated market, and cost contingencies may be based on standard percentages.