bluuebunny/crossref_metadata_2025_split huggingface dataset:
Storing Oil on the Sea Bottom to Improve the Bottom Line
Authors: Jacobs Trent 
Published: February 2015

Technology Update
The growing desire of offshore operators to speed up subsea field development while reducing costs has fostered many compelling innovations. Among those systems under development to meet this demand, and one with broad applications, is a subsea storage unit (SSU) created by Kongsberg Oil & Gas Technologies. The SSU employs the new concept
of a “flexible bag” protected by a dome for oil storage on the seafloor (Fig. 1). Depending on field conditions, the dome can be made of concrete, fiberglass, or steel. The system offers oil companies a safer, more cost-effective method of developing subsea fields in extreme weather zones or in the Arctic where ice floes are prevalent. The SSU is also being qualified for extended well testing (Fig. 2) and early production startup, and it may enhance the economics of fields with insufficient reserves to support full field development. Furthermore, the SSU could be used in place of subsea storage cells, fixed platforms, floating storage units (FSUs), and pipelines.
“It is an alternative to existing storage facilities and could also potentially commercialize the development of marginal fields,” said Astrid Rusås Kristoffersen, a subsea systems product and technology manager at Kongsberg. “The [SSU] will increase profitability of marginal fields, because the oil can be stored subsea. And then, using small shuttle tankers for more frequent offloading will precipitate the cash flow and reduce operational costs.”
Ideally, two or more SSUs could be used to maximize the allowable output volume that could be uploaded into a tanker. As production increases, SSUs could be added to the cluster. Kongsberg is considering standardizing the dimensions of the SSU to fit different needs, with the largest version on the drawing board being 131 ft (40 m) in diameter with a capacity of 120,000 bbl of oil.
Subsea storage technology has been used before in limited applications, but never has the design used a collapsible bag to store the oil. The bag is partly made of a polyester woven yarn that is coated with an impermeable layer on both sides to eliminate the possibility of seawater and oil mixing. Were that to happen, an emulsion layer could form, leading to bacterial growth that could cause corrosive damage inside steel pipe-lines and valves.
SPE Strategic Plan Identifies Four Priorities
Authors: JPT staff _ 
Published: February 2015

Strategic Plan
Editor’s note: The SPE Board of Directors approved the SPE Strategic Plan 2013–17 in March 2013. The SPE Strategic Planning Steering Committee consisted of Ganesh Thakur, SPE 2012 President and Steering Committee Chair; Mark Rubin, SPE Executive Director; Egbert Imomoh, SPE 2013 President; Ken Arnold, SPE 2012 Vice President Finance; Janeen Judah, SPE 2013 Vice President Finance; Alain Labastie, SPE 2011 President; and Jeff Spath, SPE 2014 President-Elect. Consultant and facilitator was Susan S. Meier, Principal, Meier and Associates.
Since its inception 55 years ago, SPE has remained constant in its mission to collect, disseminate, and exchange technical knowledge and to provide opportunities for professionals to enhance their technical and professional competence. SPE is increasingly aware of the impact a changing environment and global influences may have on its ability to be effective in serving an increasingly diverse membership in a highly complex industry.
By all objective measures, SPE is a highly successful organization. SPE has seen dramatic growth in member-ship globally (Fig. 1) and in the number of meetings offered (Fig. 2) to serve these members. At the same time, SPE has added new programs, expanded the reach of its programs and services, opened new offices to serve its global membership, and worked with other organizations to create greater value for members and the industry as a whole.
One SPE
Throughout this period of strong growth, SPE has strived to operate in a manner consistent with a set of One SPE Guiding Principles adopted by the Board in September 2001:
The Society of Petroleum Engineers is a diverse community of professionals that provides valuable knowledge and services to those professionals and to the industry in varied forms.
The concept of One SPE reflects the goal that each function and activity of the Society should serve the broader membership while addressing local needs, supporting technical and professional excellence, and making wise use of Society resources.
The voluntary donation of time and talent by SPE members is our most vital asset and the creative energy of volunteers must be encouraged and supported by the Society.
Dry Tree Semisubmersibles: The Next Deepwater Option
Authors: Jacobs Trent 
Published: February 2015

Dry Tree Semisubmersibles
To commercialize some of the world’s most challenging deepwater fields, offshore engineering companies are developing a new class of drilling and production platform known as the dry tree semisubmersible (DTS). The challenge involves taking existing technologies and lessons learned from previous floater designs to create an alternative platform for waters too deep to cost-justify the use of tension-leg platforms (TLPs) and fields too large for spar platforms.
Dry trees, also known as Christmas trees, are wellhead devices installed during the completion stage of a well’s life and give the operator control over production. Used on onshore wells, dry trees have been used extensively on shallow water fixed platforms, TLPs, and spars, but never on a deepwater semisubmersible because that platform’s motions are too extreme to support a dry tree system.
As the DTS concept awaits introduction into the deepwater market, multiple designs are under evaluation by major off-shore oil companies and the Norwegian classification society Det Norske Veritas (DNV).
The chief advantages of using a DTS are that opera-tors can drill, complete, and carry out intervention operations on multiple wells from the same platform in depths below 6,000 ft. This saves the operator significant resources that otherwise would be spent over the life of the field on contracting mobile offshore drilling units or purpose-built, well-intervention semisubmersibles.
Going Deeper With a DTS
A TLP typically uses four columns to support a large topside facility and is secured to the seafloor with mooring lines that allow the floating platform to move from side to side, but not up and down. Operating at a water depth of 4,674 ft, ConocoPhillips’ Magnolia TLP in the US Gulf of Mexico (GOM) is the deepest structure of its kind in the world. Next year, Chevron hopes to begin first production from its Big Foot TLP, also to be located in the GOM, at a depth of approximately 5,200 ft. Beyond 6,000 ft, TLPs become impractical because of the amount of steel needed for the tendons that moor the platform to the ocean bottom.
E&P Software: The Next Generation
Authors: Rassenfoss Stephen 
Published: February 2015

Incubator for Startups
A handful of entrepreneurs are out to disrupt the daily routines of workers in oil exploration and production (E&P) by applying digital technologies.
The entrepreneurs are members of a generation of digital natives who grew up expecting constant online contact and information, so their ideas are typically a version of how they expect the world to work.
RunTitle wants to cut the number of days spent in courthouses searching title records to find the owners of mineral rights by creating a national online database.
The Global Material Exchange
(Gmex) is creating an online marketplace for the millions of tons of steel products now bought and sold using phones, faxes, and email.
Skynet Labs plans to replace spread-sheets and manual calculations by drillers with applications that can be used on smartphones or tablets, and ultimately with a cloud-based system offering greater computing power and the ability to collaborate.
Secure Nok is going about drilling rig security from a different angle, looking for signs of trouble by closely analyzing machine performance.
Waveseis seeks to create better seismic images of formations otherwise obscured by thick layers of salt.
They are among the 12 companies in the second class of startups nurtured by the Surge Accelerator—a 2-year-old Houston venture created to use techniques developed in the technology sec-tor to jump-start early-stage companies in energy. About half the business plans are based on software to improve oil and gas operations.
Surge was founded on the premise that the energy industry is ripe for a digitally driven change that has transformed business sectors such as finance and manufacturing. “They (plans of Surge companies) are all focused on collecting data, managing data, analyzing data—all in real time—and providing actions on top of that,” said Kirk Coburn, managing director of Surge, who summed it up as “true real-time intelligence.”
Initially, Surge was investing only in software for energy—including alter-native energy and electricity—but its investment committee has added hard-ware. The group includes Dynamo Micro-power, which makes a simplified turbine that can be powered by wellhead gas to generate power. Water has also been added because it is so critical in this realm.
If these ideas turn into profitable enterprises, Coburn and the other Surge backers have a chance to profit from it. The accelerator gets a 6% stake in the companies in exchange for financial support, training, mentoring, and connections to potential investors and users during a 3-month program in Houston.
Saudi Aramco Oil and Gas Production Hits Historic Levels
Authors: Henni Abdelghani 
Published: February 2015

Production Record
Saudi Arabian state oil company Saudi Aramco released its annual report in July, noting that it produced more oil and gas last year than ever before, and also raised its technical capabilities to new heights as part of it 2020 strategy to be a fully integrated energy and chemicals company.
The company’s annual production exceeded 3.4 billion bbl of oil, equal to an average of 9.5 million BOPD. “In 2012, we produced 3.479 billion bbl of oil, about one in every eight bbl of the world’s crude oil production and the most we have produced in a single year in our history,” Saudi Aramco said in its annual report.
“During 2012 at Saudi Aramco, we responded to market conditions by producing crude oil at the highest level in our company’s history,” said Khalid Al-Falih, president and chief executive officer of Saudi Aramco.
The company’s recoverable crude oil and condensate reserves have reached 260.2 billion bbl, while gas reserves reached 284.8 Tcf. “Our maximum daily sustainable crude oil production capacity remained at 12 million BOPD during the year. Our gas plants now have a gas processing capacity of 13.23 Bscf/D,” the report said.
Gas production has also reached historic levels, as the company reported an 8.3% increase in output in 2012 com-pared with 2011 at about 3.924 Tcf/yr, the highest in Saudi Aramco’s history. The company also said that it produced 482 million bbl of natural gas liquids including 82 million bbl of condensates.
Crude oil exports increased 100 million bbl in 2012 to 2.52 billion bbl, with 53.2% exported to the Asia Pacific region followed by 16.5% to the United States, 7.4% to the Mediterranean region, and 5% to Europe.
In 2012, Saudi Aramco focused on exploring frontier areas in the Red Sea and complex reservoirs onshore and offshore. Discoveries included one oil field—Aslaf—and two gas fields—Sha’ur and Umm Ramil—bringing its total oil and gas field discoveries throughout its history to 116. Sha’ur was its first discovery in the marine portion of the Red Sea.
Industry/Research Collaboration Advances Oil and Gas Technologies
Authors: Stepankiw Mika 
Published: February 2015

R&D on Campus - Universities are working hard to anticipate the demand for new technologies and techniques as oil and gas exploration delves into deeper waters, harsher climates, and unconventional fields. Numerous universities are teaming up with the industry on projects such as modeling software, heavy oil technologies, fines migration, drilling technologies, and foam to enhance oil recovery and production. Through these research collaborations, more efficient methods are being developed to meet the increasing global consumption of oil and gas.
Petroleum Engineering Department, Colorado School of Mines, US
The Petroleum Engineering Department at the Colorado School of Mines has a large undergraduate and graduate enrollment and a healthy mix of multidisciplinary research efforts including the Unconventional Natural Gas and Oil Institute; the Marathon Center of Excellence for Reservoir Studies; the Fracturing, Acidizing, Stimulation Technology Consortium; the Energy Modeling Group; the Unconventional Reservoir Engineering Project; and the Physics of Organics, Carbonates, Clays, Sands, and Shales Consortium.
One area of focus is the Routes to Sustainability for Natural Gas Development and Water and Air Resources project in the Rocky Mountain Region. For this project, the Petroleum Engineering and the Civil and Environmental Engineering departments are working with their sister school, the University of Colorado at Boulder, and seven other institutions in a Sustainability Research Network (SRN) funded by a 5-year grant from the US National Science Foundation. The mission of the SRN is to provide a logical, science-based framework for evaluating environmental, economic, and social trade-offs between the development of natural gas resources in the Rocky Mountain Region and the protection of water and air resources. The SRN plans to give the results of these evaluations to the public in a way that will improve policies and regulations governing oil and gas exploration. “Our goal is to find the balance between maximizing the development of natural gas and oil resources for the benefits of short-term reduction of CO2 emissions from power generation and transportation, national energy independence, and national job growth, while minimizing damage to water and air resources and risks to human health,” said Joseph N. Ryan, faculty director of the research project.
Design of an Automated Drilling-Prediction System
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163709, ’Design of an Automated Drilling-Prediction System - Strengthening-While-Drilling Decision Making,’ by Samuel R. Perez Bardasz, SPE, Edwin David Hernandez Alejadre, and Armando Almeida Leon, Petrolink, prepared for the 2013 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, USA, 5-7 March. The paper has not been peer reviewed.
Data-mining processes are fundamental in obtaining the predictive benefits of real-time systems and have been progressing from descriptive to predictive optimization methods. These methods are enhanced by real-time and historic data. Advanced sensor technologies, improved data-quality control, wellsite information-transfer standard-markup-language (WITSML) data advantages, and virtual real-time drilling-optimization concepts have been assimilated into the design and implementation of prediction systems.
Introduction
As technologies evolve and the WITSML standard allows data exploitation by many specialized applications, more-accurate and reliable drilling data are available at real-time operation centers (RTOCs) to analyze and mitigate drilling issues. This enhances and speeds up the drilling-optimization process, and allows a small group of highly skilled drilling engineers to support several wellbore constructions simultaneously.
However, the traditional tasks of monitoring drilling parameters are still constrained by the constant need for human intervention. First, the particular field-operations knowledge gained by RTOC monitoring engineers is very valuable but fragile, because it requires the continued participation of team members. To ensure that nothing is overlooked, that knowledge should be gathered and used by an intelligent system. Second, the status of a particular event or well is constantly changing as key drilling factors change, and monitoring engineers must review all data in detail before manually defining the new status of a system. Third, a complete update of a general well-operations status report is time consuming. The operations status for a set of wells being drilled and monitored can change dramatically from one minute to the next and therefore requires the constant participation of an engineer. Such a report should be automated to de-rive maximum benefit from the best real-time and historic data.
Drilling-Data Mining
The drilling industry is aware of the importance of pattern analysis and past performance of correlation wells. It has looked to similar drilling-well experiences to predict the probability of a particular event or drilling outcome. This has been achieved effectively with human intervention, despite the fact that multiple data families that needed to be taken into account were difficult to access for different reasons.
Management Strategies Optimize Drilling and Completion Operations
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165325, ’A Successful Optimization Case of Drilling and Completion Operations Through Management Tools and Strategies,’ by Oscar R. Silva, Guden O. Silva, and Luis I. Valderrama, Ecopetrol, prepared for the 2013 SPE Western Regional and AAPG Pacific Section Meeting and Joint Technical Conference, Monterey, California, USA, 19-25 April. The paper has not been peer reviewed.
By 2010, all applicable drilling solutions had seemingly been applied to the Castilla field in Colombia. But new problems were identified, and a model of management strategies was implemented to reduce drilling and completion timing. During the resulting optimization process, the Castilla field became the model for the rest of the fields in the company portfolio. It is believed that this model might also be applied successfully to other fields.
Introduction
In a May 2010 evaluation, several facets of Castilla field operations were assessed: current processes, operations, and technologies; the state of drilling operations by use of management indicators; nonproductive time (NPT); field characteristics; and roles and responsibilities of personnel. The objectives were to prioritize processes by importance, create a process guide, develop a new manpower plan, improve communication, and apply technology efficiently.
Optimization Evaluation Results Field Characteristics. The Castilla field is 200 km from BogotÁ in the Llanos basin. This field has three formations of heavy oil (T2, K1, and K2) to 7,500, 8,000, and 8,500 ft in true vertical depth (TVD), respectively. Most of the wells are drilled to approximately 9,500 ft in measured depth. The majority of the wells are J-shaped, with inclinations from 30 to 70°. The most common operational problems in the field were to be found at approximately 1,000-ft TVD, at the shale formation found immediately above pay zones.
Optimization Model. The optimization process had three principal stages: implementation, consolidation, and optimization excellence. The development of each well had involved five steps during the drilling process: planning, implementation, control, feedback, and optimization. The drilling engineer had to plan the well; implement, explain, and communicate the plan; control the drilling while continuously monitoring parameters, ensuring compliance with the plan and the application of the lessons learned; catalog the lessons learned; and apply these lessons to new optimization plans.
The working optimization model was designed around several major strategies, all developed on the basis of technical limits related to health, safety, and environment (HSE): continuous monitoring of indicators; establishment of only one line of communication; application of short-, medium-, and long-term well vision; and organization based on engineering.
Comments: The Implications of Shale
Authors: Donnelly John 
Published: February 2015

Editor's column
Worldwide spending on renewable electricity generation, primarily by wind and solar, hit record levels in 2008 and remained stable last year in spite of the recession. In addition, investment in low-carbon R&D has increased by a third since 2005, production of hybrid and electric vehicles is on the rise, and energy efficiency in OECD countries has doubled in a little over a decade.
This, says the International Energy Agency (IEA), is an indication that an “energy revolution” is taking place, a shift from a hydrocarbon-based global economy to a renewable one, and one much faster than anticipated. “For several years, the IEA has been calling for an energy revolution to tackle climate change and enhance energy security and economic development. For the first time, we see early indications that such a revolution is under way,” says Nobuo Tanaka, executive director of the IEA. These are signs that the first “green shoots” of a renewable future have sprouted, he says.
But the unexpected rise of unconventional shale-gas resources should temper the IEA’s enthusiasm. Output from shale in the US and the availability of new liquefied natural gas (LNG) supplies have created a gas glut, depressing prices. Shale resources in the US and Europe are now thought to be so large as to alter the conventional wisdom about short-term energy, and geopolitical, scenarios. Natural gas has long been thought of as a bridge to the future from a hydrocarbon economy to one based on renewables because of its smaller carbon impact compared with oil and especially coal. But the rise of these unconventional resources, made available with better technology that has driven down production costs, could slow that transition because of gas’ cheap cost and availability. With an inexpensive and more environmentally friendly fuel available, it may make investment in and use of sources such as wind and solar seem less urgent.
Shale may be altering the geopolitical landscape as well. An informal gas producers’ organization was formed earlier this decade with giant producers Russia, Iran, Venezuela, and Qatar assessing the viability of such an organization that affects prices and supply. In a sense, a “gas OPEC.” But as long as local gas supplies are plentiful in North America and western Europe, the impact of such an organization is diminished. And Russia may lose its hold over parts of the European gas market as European shale output increases and LNG supplies, once thought to be directed to the US, find their way to Europe.
One thing that could derail the growth of shale is new regulation based on environmental concerns. Government scrutiny over hydraulic-fracturing techniques used in shale production has increased, and the Macondo blowout in the US Gulf of Mexico has heightened public fears of drilling and has encouraged environmental skeptics to put pressure on regulators.
But absent that, shale’s impact on the global energy market will be significant. The US Department of Energy predicts that worldwide production of unconventional gas will increase 5.2% per year from now to 2035.