bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Integrity Management Focus of Middle East Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Abu Dhabi played host earlier this year to an SPE Applied Technology Workshop (ATW) titled “Sustaining Business Excellence and Process Safety Through Effective Facilities Integrity Management.” The goal: to provide the more than 80 professionals in attendance with various perspectives on managing the challenges of ensuring safe and efficient operations in the face of aging facilities and increasing economic constraints.
Over 3 days, the ATW provided integrity-management (IM) professionals from facilities across the value chain the opportunity to share their experiences and best practices in managing the above challenges while also facing increasingly stringent health, safety, and environmental (HSE) regulations and a more competitive business environment. It also served as a platform to present and discuss equipment-specific IM systems for oil and gas surface and subsurface facilities, both onshore and off.
Some of the main points raised by the speakers and participants over the 3 days follow, summarized by topic.
IM System
One of the first day’s major topics addressed the factors that make for a successful facility IM system. Some delegates stressed that to be effectively implemented, an IM system must link to a corporation’s top objectives and be supported at all levels. The system needs to be driven in a top-down manner, with top management taking a leadership role and clearly communicating the system’s stated objective down the line to technicians and operators on the ground such that IM awareness becomes part of their daily activities, much like personal safety.
One delegate drew the analogy that just as a cake includes common ingredients, any IM system also includes common components, including management of change, competence, learning, risk management, and standards.
A successful system should envelop the whole life cycle of a facility and include assess/select phases at the earliest project stages, when maximum risk reduction could be achieved. Integral to this is a clear definition of the facilities’ physical boundaries and operating envelopes, as well as the establishment of key performance indicators (KPIs) to monitor the system’s effectiveness. These KPIs should be clearly linked to corporate objectives, consistent throughout a given industry to allow for bench-marking, and have the right mix of indicators for lagging vs. leading and effectiveness vs. efficiency.
Other delegates stressed that system implementation should not take a “one-size-fits-all” approach because different companies may have to take different approaches, even though they all have similar ultimate objectives in ensuring that their assets remain running safely and with a minimum of down time. The system should be driven by an established mature framework, and should clearly define accountabilities by nominating competent persons and technical authorities for key roles.
Finally, an IM system should be developed as a system of continuous improvement.
FPSOs Enter The Gulf Of Mexico Operator Tool Box
Authors: Lovie Peter 
Published: February 2015

Editor’s note: This is the second of two articles on the technical challenges and regulatory hurdles that were overcome to allow the use of floating production, storage, and offloading vessels (FPSOs) in the US Gulf of Mexico (GOM). The FPSO that will be installed at Petrobras’ Cascade/Chinook development in the deepwater GOM is planned for mid-2010 startup.
As 2006 progressed, teams of operators’ engineers continued deliberations on how to make a start on producing two US Gulf of Mexico (GOM) field developments using a floating production, storage, and offloading (FPSO) vessel as an early production system (EPS). One team decided against it and the other agreed that an FPSO did make good sense for its field. It was an interesting contrast in the philosophies of two operators: one (Chevron) very deliberative and exhaustive, investigating all options before proceeding and only then in a tightly organized project management and planning structure; the other (Petrobras) with a more pragmatic approach, borne of the uncertainties faced in production from these untested formations and their success in Brazil in trying out production for a short period at new fields (Fig. 1).
The use of an FPSO was agreed for the Petrobras-operated Cascade/Chinook development (Devon as a partner on Cascade and Total on Chinook). At multiple standing-room-only technical sessions at the 2007 Offshore Technology Conference in Houston, the offshore industry debated and settled on design-code revisions. Simultaneously, negotiations proceeded on contracting the first FPSO for the GOM, and August 2007 saw the contract signed for chartering the first FPSO in US GOM waters, for the Cascade/Chinook development. Competition had been fierce for this pioneering project.
Within weeks, two new shuttle tankers were chartered to provide export to GOM ports. This was not as simple as it sounds, as these tankers would transport oil from one US port (the FPSO) to another US port (the shore terminal or refinery) and so had to conform to the Jones Act, which stipulated that
Crews had to be US citizens.
The ownership of the tankers had to be at least 75% US.
Tankers for Jones Act trade had to be built in the US.
All of the conditions translate to high capital expenditure and day rates, approximately 2–3 times that of a non-Jones Act tanker. The Merchant Marine Act of 1920 (The “Jones Act”) does apply to shuttle tankers, but does not apply to FPSOs.
By standards elsewhere in the world, the shuttle tankers used in the US GOM are not particularly efficient—they are small (approximately 330,000 bbl capacity) to enable entry into US GOM ports with 40 ft draft restrictions, and must have alternate use in products service in US waters if the shuttle-tanker business does not continue.
Technology Focus: Multilateral/Extended Reach (May 2010)
Authors: Negrao Alvaro 
Published: February 2015

Technology Focus
Exploration and development projects suffered from uncertainties caused by downsizing of the worldwide economy last year. Wide variation in value of our main commodities caused delays in several offshore oil- and gas-asset projects.
Our industry must ask if it has done enough to deal with these variations in commodity values and what would be the best way to mitigate their influence in the current market. Current statistics show that there is a long way to go. The cost of nonproductive time (NPT) is very high and needs to be mitigated. The importance of improvement performance in a critical economic environment is crucial to maintain our business. The main question is how to keep the interest of investments in this scenario.
Fundamental to evaluating techniques, equipment, and design is understanding the risk variability. Professionals must respond to a more-fluid, less-certain business environment than did their predecessors. Assessing data and planning and executing a well involve a complex interaction of data, regional knowledge, and field experience. Different subjects not considered before such as communication skills, adding value, team building, and networking have a major role in mitigating the risks and in improving the performance and financial return of a project. These dynamics, along with increased globalization, require a broader set of skills.
We are succeeding in drilling and producing wells in water depths and measured depths greater than 10,000 and 35,000 ft, respectively. However, decreasing NPT to acceptable ranges has not happened. Although innovative technologies have been implemented over the last 10 years that enable exploration and development in environments with difficult tectonic stress and subsalt or presalt wells, we still lack efficiency. In offshore operations that cost our industry more than USD 1.3 million/D, the current NPT between 20 and 30% in several areas of the world is not acceptable.
For the sake of future business, operators and service companies should work together not only in development of new technologies but in aligning common goals such as a consistent NPT less than 5% in operations, which would guarantee several projects. This target requires a common goal of operators and service companies who, unfortunately, to date, have not been brought together, but in the current environment it is essential for our future.
Multilateral/Extended Reach additional reading available at OnePetro: www.onepetro.org
SPE 128314 • “Multilateral Wells Reduce CAPEX of Offshore, Subsea Development in Australia’s Northwest Shelf” by Brett Lawrence, Apache Energy, et al.
SPE 128461 • “Successful Application of Dual-Lateral Junction Technology To Develop a Marginal Gas Field in the Carboniferous Area of the UKCS Southern North Sea” by A.J. Hatch, E.ON Ruhrgas, et al.
SPE 128915 • “An Experimental Study To Define Operational Parameters Governing Hole Enlargement While Drilling Offshore Heavy-Oil Reservoirs” by F.G. da Costa, Petrobras, et al.
Technology Focus: Well Construction (May 2010)
Authors: Carpenter Bob 
Published: February 2015

Technology Focus
In 2009, the focus of well-construction technology was primarily in two areas: our ability to drill and reliably complete deepwater and high-pressure/high-temperature projects and exploration of the reliability of carbon-capture and -sequestration (CCS) storage wells. Outside these big focus areas, some papers relating construction practices specific to the shale plays are beginning to come forth.
Lost circulation is still one of our biggest obstacles to getting deepwater wells to target depth. Unfortunately, lost-circulation issues are expected to become even more difficult in these fields as pore pressure drops because of production and depletion. In one paper, details are presented of higher-risk squeeze techniques used to shut off high-rate losses, enabling completion of two potentially lost wells. The full paper may be a good read the next time you find yourself in such a situation.
As we discussed here last year, CCS is our next big area of activity. Progress and acceptance of CCS depend upon very-long-term isolation of the injected CO2. One of the big questions with CCS-well construction is whether special non-Portland or lean-Portland cements are required to ensure the long-term integrity of CO2-injection wells. If so, what does that imply for all the pre-existing wells in the storage area? Much of the early work on this subject has been contradictory. Another paper here describes the industry’s efforts to establish the potential leak paths and to prescribe appropriate construction techniques.
Using simple, tubing-sized monobore completions has proved an effective and efficient development strategy for complex multilayer reservoirs. The simplicity and reliability of the wireline tools we run in these small monobores are critical. John Lofton, one of Chevron’s drilling-engineering advisors, was intrigued by the novel, field-tested design evident in the retrievable lock mandrel described in another paper highlighted here. Retrievable tools embodying such features may provide improved reliability for slim monobore completions in hostile environments.
Well Construction additional reading available at OnePetro: www.onepetro.org
SPE 125642 • “Optimizing Openhole-Completion Techniques for Horizontal Foam-Drilled Wells” by Dave Allison, SPE, Halliburton, et al.
SPE 128226 • “Self-Healing Cement System—A Step Forward in Reducing Long-Term Environmental Impact” by S. Le Roy-Delage, SPE, Schlumberger, et al.
SPE 126226 • “Effective Zonal Isolation for CO2-Sequestration Wells” by R.E. Sweatman, SPE, Halliburton, et al.
Comments: Looking Ahead (May 2011)
Authors: Donnelly John 
Published: February 2015

Editor's column
Top executives from an operator, service company, drilling contractor, and financial services firm spoke recently in Houston about the short- and mid-term outlook for the oil and gas industry. They agreed that the industry is undergoing significant changes as it transitions to new market structures amid increased advanced technology demand.
Oil and natural gas prices should continue their current trend, with oil prices rising and gas prices under pressure from ample supply, said Marshall Adkins, director of energy research and managing director of equity research at Raymond James & Associates. He spoke at the Decision Strategies’ industry forum, a widely attended occasional gathering in Houston. Several factors will continue to contribute to higher oil prices over the next five years, he said, such as Middle East instability, a leveling off of non-OPEC production growth, the impact of the US Gulf of Mexico drilling moratorium, rising demand in China, and questions about the extent of OPEC’s production capacity.
The shale boom in the US is weighing on gas prices and, despite those low prices, the economics of gas drilling remain solid, Adkins said. US well productivity is up five to 10 times over the past several years, as advanced technology in shale formations has led to efficiencies. The US gas supply is projected to rise 7.5% this year and another 6% in 2012.
Robert Parker, executive chairman of Parker Drilling, agreed that the drilling moratorium in the US Gulf of Mexico along with the emergence of shale production has greatly altered the short-term supply outlook, and contributed to the divergence in oil and natural gas prices. A real wild card in any future global supply/demand outlook is the growing political instability in some of the larger producing countries, he said.
Notable will be how the US shale boom translates to other countries—infrastructure hurdles may limit production in some countries and shale oil production may eventually prove more prolific than shale gas. China and Argentina have strong shale potential and, in the Middle East, Saudi Arabia is a good bet.
Over the next several years, service companies, international oil companies (IOCs), and national oil companies (NOCs) will continue to adapt to a changing industry landscape. Several market forces are combining to change expectations for service companies, said Chad Deaton, chairman and chief executive officer of Baker Hughes. Growing hydrocarbon demand, the increasing importance of NOCs, the need for advancements in technology, and the increased importance of deepwater production and in maximizing recovery factors have broadened the scope for the service sector in operations projects. “The oil and gas industry is one place where technology really drives economics,” he said.
Can the Oil and Gas Industry Live Up to Today's Dynamics?
Authors: Al-Khalifa Abdul-Jaleel 
Published: February 2015

Guest editorial
The continual change in Middle Eastern dynamics will have a profound impact on the oil and gas industry. Brent crude spiked when events escalated in Libya. The panic is about security of supply rather than space capacity, considering its abundance in the current oil markets. In other words, the market doubts that the current pro-customer oil policy in terms of pricing and production can be maintained going forward.
Changes in the 1960s brought OPEC into existence and changes in the 1970s delivered higher oil prices. Most importantly, these changes shifted global oil leadership from international oil companies (IOCs) to national oil companies (NOCs). So, how will the oil and gas industry adjust and reshape under today’s dynamics?
Historically, the oil and gas industry has had a narrow focus on the bottom line of creating value for shareholders. The shareholder is the government for NOCs while it is public investors for IOCs. Both strive to maximize financial earnings while delivering cost-effective performance applying state-of-the art technologies. While NOCs consider government’s responsibility to meet community needs such as job creation and sustainable growth, IOCs have focused on corporate social responsibility aimed at improving their public image. This “profit-only” business model, however, has started to fail, especially in the Middle East.
One can argue that one of the catalysts of recent Middle Eastern change is the poor standard of living in large local communities, while billions of dollars accumulate in the hands of business dealers. Many held the wrong belief that such business pockets could ensure stability and a secure supply of energy at the expense of the community at large. It was further exacerbated by companies focusing on their core business while outsourcing utilities, food catering, medical, IT, and other services. As such, companies have laid off or retired thousands of national employees, leaving room to employ nonlocal employees at cheaper rates. This has severely shrunk the value of the oil and gas industry in the eyes of some local communities.
The industry has also failed, most of the time, to build a complete chain of industrial and services support that provide job opportunities and circulate liquidity into the local economy. It is devastating in some cases when operations have to be halted to wait for a service hand to fly overseas to service tools and facilities. Billions of dollars worth of contracts to build new oil and gas facilities are also being awarded to international contractors. Both detailed engineering and procurement are sourced abroad. Furthermore, at the construction stage, the contractors normally fly in thousands of cheap nonlocal labor. While Houston is the oil capital in the Western Hemisphere, the Middle East, home to two-thirds of global reserves, does not have an energy capital yet. This only speaks for the industry’s narrow focus and failure to stimulate local industrial support.
Oil and Gas: Into the Cloud?
Authors: Feblowitz Jill 
Published: February 2015

Management
Anyone who has watched television lately has seen commercials about amazing things being accomplished in the “cloud.” Advertisements are focused on what the typical consumer can do, such as sharing and editing photos, but benefits of the cloud—lower information technology (IT) costs, less complexity, and speed to launch—have been touted for business as well. The oil and gas industry has been on the forefront of adopting emerging technologies such as high-performance computing. The industry is knowledge intensive and is even experimenting with social networking. The question is whether the industry, given its global nature, need for security, and existing legacy infrastructure, will take to the cloud.
IDC Energy Insights defines cloud services as business and consumer products, services, and solutions delivered and consumed in real time over the Internet. The public cloud is a deployment model where the cloud is open to a largely unrestricted universe of potential users. In fact, the public cloud has been a part of the IT landscape for several years, mainly in the form of software as a service. A good example is salesforce. com, which is designed for specific purposes, but not for a single enterprise. Public cloud includes but goes beyond software as a service to IT infrastructure or platform as a service. The private cloud is designed for restricted access to a single enterprise (or extended enterprise). A hybrid cloud combines a private cloud with the use of public cloud, especially when internal private cloud resources are strained. Fig. 1 displays the key attributes of the cloud.
The cloud services model, by leveraging all eight of these attributes together, makes business and consumer cloud services easier and cheaper—and often better—to consume than through traditional delivery modes. These attributes are lower costs (for customers and suppliers), speed and simplification of access, speed and fine-tuning provisioning (in line with true demand/usage), greatly increasing the number and variety of available services (thanks to lower development and deployment costs and standards), and improving the potential to integrate.
Despite the popularity of the cloud in some applications, cloud computing has still not aggressively penetrated the oil and gas industry relative to the pace of adoption in other industries. According to IDC’s 2010 Vertical Group Survey, 10.3% of oil and gas companies are currently using or implementing cloud computing and 7% have cloud computing on their technology road map (Fig. 2). Forty-two percent of the companies that said they would use the cloud in 2010 were spending less than 5% of their IT budget on cloud.
Carbon Capture and Storage: A Mixed Review
Authors: Beckwith Robin 
Published: February 2015

The overall tone of the report, titled “The Global Status of Carbon Capture and Storage (CCS): 2010,” released in March by the Global CCS Institute, is cautiously optimistic. “The global commitment to CCS remains strong,” according to the findings of the Australia-based institute, whose 287 members include major businesses, research organizations, and governments of top emitters, led by China, the US, Russia, and India.
The report states that well over 200 CCS projects were active or planned worldwide at the end of 2010, a net rise of 26 from 2009. Of these, 77 are large-scale integrated projects at various stages of development. North America, Europe, and Australia are home to 87% of all projects, despite the largest global growth in energy usage—a major driver of human-generated CO2 release—expected outside these continents over the next few decades.
The report cautions that “governments and industry are still in the early stages of implementing international programs to shorten the time-frame for the commercial deployment of CCS.” The current phase, likely to last more than a decade, focuses on demonstration programs that develop and improve capture applications and that prove safe and secure long-term CO2 storage.
Despite major efforts like the EU Emissions Trading System, controlling or curtailing the release of CO2 remains a relatively low priority on a global basis. Nonetheless, CCS project development is currently largely being driven by government incentives across the globe. According to George J. Koperna Jr., vice president, Advanced Energy Resources, “The role of government in energizing the industry is terribly important.” The report cites as much as USD 40 billion in government funding that could be available to support the development of CCS demonstration projects over this decade.
The Goal and Today’s Progress
The Intergovernmental Panel on Climate Change estimates the world’s average surface temperature will increase between 1.8°C and 4.0°C in the coming century. According to the International Energy Agency (IEA), around 20% of the total greenhouse gas emission reductions necessary to help mitigate this increase by 2050 can be achieved through CCS.