bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Standards for Safety-Critical Elements - Are We Doing Enough?
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140727, ’Performance Standards for Safety-Critical Elements - Are We Doing Enough?,’ by Rahul Dhar, SPE, Abbott Risk Consulting, prepared for the 2011 SPE European Conference on Health, Safety, and Environmental in Oil and Gas Exploration and Production, Vienna, Austria, 22-24 February. The paper has not been peer reviewed.
Safety-critical-element (SCE) life-cycle management involves identifying major accident hazards (MAHs); selecting SCEs by identifying structures and plants that can cause, contribute to, prevent, or help recover from a major accident event; and developing the performance standards (PSs) for the identified SCEs. It also involves alignment of maintenance routines, inspection and testing, performance history, and other tasks required to maintain the SCE in a suitable condition. Continual monitoring of the status of the hardware barriers and performance-assurance tasks enables the operating staff and management to analyze the ongoing conformance of the SCEs by use of their PSs.
Introduction
Although much has been achieved by the oil and gas industry in terms of reducing risk to personnel, the environment, and assets by use of SCEs and PSs, major accidents continue to happen. The concepts of SCEs and PSs have been presented to prevent or reduce the number of major accidents. MAHs or major events are defined differently in different parts of the world, but have a common underlying theme in that they can cause harm to multiple people, cause substantial environmental damage, or cause expensive damage to the assets. The author highlighted three headline events in the full-length paper to promote thought on the topic: the Montara wellhead-platform blowout in 2009, the Deepwater Horizon accident in 2010, and the Ocean Ranger semisubmersible sinking in 1982. These events suggest that, perhaps, not enough is being done and, therefore, more effort must be made to reduce the number of major accident events or possibly prevent them.
Need for SCEs
Reliable Design and Engineering (Good Practices). SCEs and their PSs ensure that new installations or designs con-form to current good practice and reliable engineering. For new installations, it is extremely important that their design be robust and that they be able to perform their intended functions throughout their design life.
Aging Installations. As current oil and gas installations get older, it is important to ensure that they remain capable of performing intended functions in the safest manner possible to avoid harm to personnel or to the environment. SCEs and their life-cycle-management processes help achieve these goals and reduce or prevent the major accidents.
Innovation: Well Evaluation Innovation
Authors: Imomoh Egbert 
Published: February 2015

President's column
From the earliest drilling operations, the need for operators to see the penetrated formation was paramount, in their minds. They needed to distinguish not only the rock properties but also their content and deliverability. The first electrical well-logging operation took place in 1927 after many years of successful experiments with surface resistivity measurements by Conrad and Marcel Schlumberger. The operation, in France, took more than 5 hours to record the resistivity over an interval of 140 m from a depth of 279 m. Henri Doll, one of the three wellsite engineers at the operation, wrote “We began making our measurements. Someone had to unplug the connector, someone else turned the winch. Someone had to run to the rig floor to look at the counter on the sleeve. I wrote down the measurements on a pad together with the depth... Then it was unplugged, rolled up one meter at a time.” (Schlumberger 2007)
Four years later the spontaneous potential of a formation could be measured, thus allowing permeable rock to be distinguished from nonpermeable rock. These measurements are far from the sophistication of today, but for me this demonstrates how seemingly simple innovations have made such a tremendous impact on our industry. The equipment currently used for logging wells and capturing and transmitting data is a far departure from the rudimentary operation that took place 85 years ago. The point is that the industry saw the need for the nascent technology, and its use all over the world allowed not only the measurements around a wellbore, but also provided results with which the geologists could match well correlations, map a field, and obtain the structure of the horizons.
Innovative ideas emerging in other industries began to have an impact on our well evaluation operations. The development of electronics in the 1930s led to a number of new developments in logging operations. The miniaturization of rugged circuit boards and components led to new tools that suffered less damage, which in turn reduced lost time during rig operations. The introduction of computers permitted the capture and interpretation of data. Transmission of data from wellsite to office has been enhanced by innovation in the telecommunications world, and remote logging operations have been enhanced by the use of satellite and other forms of telecommunication. Modern technology now permits multilocation access to live data from rig sites, thus permitting real-time management of situations that leads to speedy interpretation. When I worked on a wellsite in the late 1960s, logs were developed on site and physically moved by road, boat, or helicopter to the office-based engineers for evaluation; subsequently, further instruction was transmitted back to the wellsite by unreliable high-frequency radio. I can still recall the smell of ammonia used for printing those logs. I recently mentioned this to a few young engineers and the blank look on their face made me feel as if I was from the Stone Age, but that is what innovation has done in our industry.
UK's Gas Heritage May Become Its Legacy
Authors: Pickering Tom 
Published: February 2015

Guest editorial
The United Kingdom is attempting to emulate the unconventional gas bonanza that has transformed the United States from having an energy industry that was in its “sunset” era to a nation rich in energy resources. The UK, which sits on significant shale reserves, wants to become part of this game-changing industry, viewing it as an exciting opportunity as it looks to revolutionize the energy landscape for the next generation.
By its very nature, the country has a dense population with a rural and agricultural countryside and, though it boasts a huge offshore infrastructure, lacks onshore support and infrastructure. Add the obstacles of environmental concerns, a need to build awareness, and a cautious political uptake, it could take 2 more decades before investment decisions by industry could turn concern about the value of unconventionals into certainty.
Unconventional gas has a particular production profile and economics; consequently, operators must be able to drill, produce, and build facilities within tight cost parameters, which can be marginal. The underpinning culture and supply chain in the North Sea is not as conducive to that development. Therefore, it is crucial that there is a fundamental shift in the approach toward equipment, infrastructure, service industry support, and onshore and community stakeholder engagement.
Historically, the UK and Europe have engineered large gas deposits offshore and deployed pipeline and transport facilities to handle the delivery of large volumes of conventional high-pressure gas to market. Therefore, the existing base infrastructure presents a costly challenge for unconventional operators seeking entry into the industry. It is also true that where there has been the opportunity to turn gas into electricity by generation, both the generating and distribution network is geared to high-voltage, coal-fired power stations and nuclear electricity generation.
The story now centers on the indigenous supply of natural gas. Five years ago, it looked as though the world might have only 50 to 60 years’ worth of gas. However, by some estimates, shale and other unconventional gas finds have increased that life span to 200 years or more.
The successful exploration, appraisal, and development of UK onshore unconventional resources have the potential to provide a significant contribution to the hydrocarbon component of the nation’s balanced portfolio and strategy.
Despite the technical, environmental, financial, and political challenges, the UK and other European countries, are taking the first tentative steps to establish the development of shale and coalbed methane. Coring activity is now under way in reservoirs to ascertain the presence of gas, geological permeability, and the natural fracture system within the rock, and that presents an encouraging commercial opportunity.
Subsea Corrosion/Erosion Monitoring
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
Detection and monitoring are important prognostic means in preserving material integrity and reducing the life cycle cost of industrial infrastructure, ships, aircraft, ground vehicles, pipelines, oil installations, etc. Having better control of your infrastructure’s condition will enable you to optimize profitability and lower maintenance cost. Hence, monitoring an oil and gas pipeline will not only work as a precaution, but can also give information on when replacement or repair is necessary, thereby maximizing uptime. There is a huge need for reliable monitoring of pipe wall thickness, both topside and subsea. Even in topside applications, the conditions of operation may be hostile and problems such as large temperature variations, lack of space, fluid loading issues, and a host of other factors make development of such a tool a challenging task. Going subsea makes it even more demanding when you have to take into account factors such as high pressure and limited access.
Over the past years, ClampOn has offered a corrosion/erosion monitor (CEM) for topside installations. Major advantages of this technology are its noninvasiveness, high repeatability, lack of any transducer movement, and high coverage. The measurement principle is based on dispersion of ultrasonic-guided wave modes, and by using electromagnetism, these waves are transmitted along the pipe wall without the sensor being in direct contact with the metallic surface. This makes it an excellent candidate for subsea use. It is installed on the outer pipe wall to produce real-time wall thickness information, not as a spot measurement, but as a unique average path wall thickness. With several successful installations topside, the ClampOn CEM has also found applications subsea, with the first unit installed at 2300 m in the Gulf of Mexico in February and another 10 units to follow in the future.
Corrosion and erosion in subsea installations is detected by several methods. In topside applications, the alternatives are both more reliable and many. In subsea applications, the more hostile environment makes the detection of corrosion and erosion a more challenging task. Piggable pipelines are normally inspected at regular intervals and tracking of pipeline integrity is in general not problematic. Some unpiggable pipelines can be inspected using cable-operated tools, but such inspections are expensive and may require a shutdown of production. Subsea production templates, flow jumpers, manifolds, and flow lines can today only be inspected by preinstallation of corrosion/erosion sensors or by use of sensors controlled by remotely operated vehicles (ROVs).
Keeping the Pipeline Full
Authors: Rassenfoss Stephen 
Published: February 2015

Large infusions of money and new technology will be needed to fill the oil gathering systems in the West Siberian oil fields. The owner of this field, Salym Petroleum Development, hopes to increase the output of its fields using chemically enhanced oil recovery and by producing oil from the Bazhenov formation.
Russia Considers Its Unconventional Options
To search online for the story of how Russia became one of the world’s top oil producers, try the keywords “West Siberia.” For the future, try “Bazhenov.”
The Bazhenov is the source rock for the prolific West Siberian fields that still yield about two-thirds of Russia’s crude oil production nearly 50 years after the oldest of those fields went into production.
The formation covers an enormous area—conservative estimates put it at more than 1 million km2, which is 1.5 times as large as the US state of Texas. The low-end estimate of the total reserves in the Bazhenov by a national agency that estimates Russian resources in the ground, Rosnedra, is 182 billion bbl, according to Platts, an oil industry trade publication. The high end is double that total.
Now, some of the biggest oil companies in Russia, and the world, are trying to figure out how to convert that resource into reserves. Bazhenov wells have been drilled for decades, and have earned the formation a reputation for unpredictability.
The drive to take what has been learned about unconventional oil production in the US and use it in West Siberia was a key theme at the recent SPE Russian Oil & Gas Exploration and Production Technical Conference and Exhibition in Moscow. Another theme was the growing list of techniques being employed to extract more oil out of conventional formations: from using advanced seismic analysis, to new drilling and completion methods to tap unproductive formations, to enhanced oil recovery (EOR) using chemicals.
An example of all of the above is Salym Petroleum Development (SPD). The 50/50 joint venture between Shell and Gazpromneft, a Gazprom subsidiary, has been investigating the Bazhenov in its fields in West Siberia, where it has also been drilling hundreds of wells based on advanced seismic studies to reach unproduced zones. And it is testing chemical EOR.
Based on lab work and a single-well field test, using alkaline surfactant polymer (ASP) treatments could significantly increase its ultimate production, Simon Durkin, chief executive officer of SPD, said in an interview during the Russian conference. Using chemicals to free more of the oil from the formation and improve the sweep of a waterflood could add more than 100 million bbl of incremental production over 30 years, according to company estimates.
Who Drives E&P Innovation?
Authors: Perrons Robert K. , Donnelly John 
Published: February 2015

Management
Few would argue that the upstream oil and gas industry has become more technology-intensive over the years. At the same time, the increasing costs and complexity of today’s exploration and production (E&P) technologies are making it increasingly difficult for any one company to support an aggressive research and development (R&D) agenda single-handedly. The coming together of these two evolutionary forces gives rise to important questions. How does innovation happen in the E&P industry? Specifically, what ideas and inputs flow from which parts of the industry’s value network, and where do these inputs go? And how do firms and organizations from different countries contribute differently to this process? This survey was designed to shed light on these issues.
Consisting of 23 questions, this survey asked respondents about several aspects of their business unit’s R&D and innovation-related activities. Much of the survey focused on the sources of knowledge they rely upon throughout their innovation activities. What sources of information, data, and knowledge are most important as they develop new technologies? This part of the survey was modeled after the Eurostat Community Innovation Survey, which has been used in more than 60 academic articles for measuring the knowledge inputs that go into innovation-related activities (Laursen and Salter (2005) and Cosh and Zhang (2011) are specific examples of research that have used this type of framework for analysis). The framework consists of 16 potential sources of knowledge (Table 4). Respondents were asked to identify the degree to which they had used each of the sources throughout the past 3 years, ranging from “not used” to “high use.”
The survey also asked for several measures of R&D output from their business unit, including the number of patents arising from technologies principally developed by their business unit in the past 3 years, the number of technologies deployed by their business unit in the past 3 years, and the number of radical innovations among these. All of these output measures were self-reported by the respondents. Respondents were informed before completing the survey, however, that their results would be made anonymous and aggregated with data from other respondents, thereby removing any incentive to distort their responses.
Respondents were asked at the end of the survey if they would object to being asked a few clarifying questions about their responses. Several said yes, and a handful of follow-up discussions were carried out to deepen an understanding of the survey results.
Unconventional Resources Headline SPE Annual Conference
Authors: Henni Abdelghani , Rassenfoss Stephen , Beckwith Robin , Dunnahoe Tayvis , Boschee Pam , Parshall Joel , Donnelly John 
Published: February 2015

Conference review
Best practices in developing unconventional resources was one of the main themes during the 2012 SPE Annual Technical Conference and Exhibition (ATCE), held in San Antonio in October. The conference brought together 11,095 oil and gas professionals from around the world, making it among the top five highest attended ATCEs.
The technical program represented all six SPE technical disciplines with an expanded focus on the projects, facilities, and construction (PFC) discipline. New PFC sessions, including a special panel dinner on megaprojects, were part of SPE’s yearlong emphasis on the discipline.
Monday’s opening general session addressed the event’s unconventional theme with a panel of experts discussing the technological and financial challenges associated with unconventional oil and gas resources. David Hobbs, chief energy strategist at IHS CERA, moderated the panel that consisted of Mark Albers, senior vice president of ExxonMobil; Timothy Dove, president and chief operating officer of Pioneer Natural Resources; Steve Holditch, director of the Texas A&M Energy Institute; and David Lesar, chairman of the board, chief executive officer, and president of Halliburton.
The rush to develop unconventional resources has been an unstructured, chaotic, often costly learning experience that is still in its early days, according to the panelists. Ultimately, the opportunity to develop resources once seen as impossible to produce is likely to be an industry-changing experience.
“It is about transforming an entire industry to operating in a new and dynamic environment,” said Mohammed Al-Qahtani, vice president of petroleum engineering at Saudi Aramco, during his introduction to the panel discussion on making unconventional resources conventional.
The changes they described range from how engineers develop fields to what they say about what they do.
The furor over fracturing has forced the industry to address critics who say the technique is a threat to water supplies. “We need to educate the public to the risks and how we are managing them,” Albers said.
The push to maximize profits and minimize costs has altered relationships as companies consider whether the traditional division of labor makes sense.
“It is a business free-for-all,” with oil companies buying and running rigs and service companies taking on reserves, said Lesar.
The US has become a magnet for exploration and production professionals from around the world because of the boom in unconventional resources, said Holditch. While the United States is seen as a university for those looking to learn shale, much remains to be learned. A favorite phrase among the panelists was, “It is early days.”
Correlating the Returns of Oil-Producing Projects Realistically
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150909, ’How To Measure the Correlation Between Return of Oil-Production Projects Realistically,’ by G.A. Costa Lima, SPE, A.T. Gaspar Ravagnani, SPE, and D.J. Schiozer, SPE, Unicamp, prepared for the 2012 North Africa Technical Conference and Exhibition, Cairo, 20-22 February. The paper has not been peer reviewed.
Portfolio theory has been an important tool for economic-risk management. There are only three input parameters: mean return, standard deviation of return, and correlation between pairs of such things as assets, projects, and prospects. Although the model is simple, a problem with it is estimating the correlation because there are no historical data. Alternatively, correlation on return of projects is assumed subjective (typically 70%), but with this model it can be estimated in a much more sound way. Results indicate that the main determinants of correlation are fixed cost, variable cost, and oil quality. With this information, managers can select best portfolios (e.g., by means of farm in and farm out) to create value for stakeholders considering means, risk, and possible benefits from diversification.
Introduction
Often, decision makers must manage portfolios containing many projects, including exploration, development, production, and decommissioning. The life span of these portfolios is similar to that of the company, possibly several decades. Most company portfolios are updated yearly. In this process, the return to stakeholders depends on such factors as the skill of decision makers to add and remove projects, performance of individual projects (and the synergistic interaction in terms of geologic features), operating infrastructure, and marketing conditions.
In portfolio management, decisions are made on the basis of the mean and standard deviation (risk) of the rate of return of investments. The risk depends on the standard deviation of each individual asset, correlation between pairs of assets, proportion of investment allocated in each asset, and the number of assets in the portfolio. Of these variables, only the risk of the individual asset is beyond the manager’s control because it depends on variables such as oil production, operating cost, fiscal regime, reservoir conditions, and geologic aspects; therefore, it is called systematic risk.
The use of portfolio theory to solve real-world problems depends strongly on calculations/estimations of correlations. Therefore, the focus in this paper is on the methodology to estimate correlations between pairs of net present value (NPV) of oil projects.
Correlation vs. Diversification
Consider an oil company with an opportunity to construct a portfolio having two oil-production projects. Initially, professionals complete a traditional economic analysis at the project level to estimate mean and standard deviation of the NPV of each project. Results of this initial analysis are shown in Table 1.