bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hands-On Teaching for Petroleum Engineers in the Twenty-First Century
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 160017, ’Hands-On Teaching for Petroleum Engineers in the Twenty- First Century: A Balance Between High-Tech and Simple Demonstrators’ by Catalin Teodoriu, SPE, ITE/TU Clausthal, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.
Several years ago, a new concept of teaching undergraduate and graduate students was introduced at the Clausthal University of Technology (CUT) based on the implementation of hands-on teaching systems that not only expose the students to physical models but also require them to build such models or to generate experiments using existing models. The results show an improved learning capability in combination with better knowledge transfer between teacher and students. This paper presents the results of student competitions held at CUT.
Introduction
Several governmental associations have reported that the teaching process in engineering schools is too theoretical. In the 3-year program implemented at CUT, hands-on teaching is focused on simple demonstrators that are designed and built by students under faculty and staff supervision. Petroleum engineering is one of the sciences that cannot always be experimentally shown in a straight-forward fashion (for instance, imagine reservoir engineers trying to show a replica of the reservoir in full scale!). Drilling and production systems and processes are easier to model. Field trips are always welcome, but they take time and the students have to give up other important courses.
The mentoring process has been identified by SPE and the industry to be a key in preparing future engineers. But are the students ready for the mentoring process? During the CUT project, students are not only involved in their design project, but are also guided toward the acceptance of mentoring and preparation for a career.
When teaching freshmen, the focus is on providing them the basics for their future career in terms of applied mathematics or physics. They are expected to calculate and estimate complicated processes, but sometimes we forget to ask them such basic questions as, “Do you know what a drillstring looks like?”
Goals of the Hands-On Teaching Initiative
The objectives of the hands-on teaching initiative include the following:
Development of hands-on and visual tools to enhance learning opportunities
Integration of theoretical and hands-on experiences into lectures
Determination that the equipment developed has an impact on core courses in drilling engineering, advanced drilling engineering, completion, and workover
Improvement of critical thinking and problem-solving skills of students by involving them in the learning process, allowing individual experimentation, and providing for tool interchangeability
Development of visual aids for students and young people visiting the department
Technology Focus: Sand Management and Frac Pack (October 2013)
Authors: Azeemuddin Mohammed 
Published: February 2015

Technology Focus
Sand production is an unintended consequence of oil and gas production from unconsolidated and semiconsolidated reservoirs, causing damage to surface and subsurface well equipment and reducing the hydrocarbon productivity. Sand production has been one of the major challenges facing the oil and gas industry for decades. It continues to be so, despite many advances in the modeling and predictive capabilities, deployment of sophisticated measurement and sand-control devices, and improved surface handling capabilities.
The challenge keeps growing as we move into more-complex and -mature reservoirs involving high development costs and lower recoveries. Sand production has traditionally been minimized through active means, such as installing appropriate sand-control devices, limiting drawdown (rate of production), or both. Another approach to limiting the damaging effect of sand production is to allow it to take place at a controlled rate along with hydrocarbon production. The produced solids then are removed at the surface upstream of the choke. This will allow a sustained rate of oil and gas production, simultaneously minimizing sand production’s negative effects on surface facilities. The choice of additional costs of installing sand-control equipment must be weighed against the incremental benefit derived from it, not only at the current reservoir conditions but also throughout the life of the well or field, considering depletion and associated stress change.
Safe and economical field exploitation calls for continued efforts and advancement in the understanding of rock behavior under in-situ conditions, both current and expected; accurate modeling of downhole conditions through fit-for-purpose failure models and modeling techniques and tools; and effective implementation of field strategies.
The papers I have selected touch upon some of the ongoing efforts in these areas and by no means represent a full coverage of the wide spectrum of efforts under way. Additional interesting papers involving field applications and case studies, in no way less important, have also been identified.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 158922 Unraveling the Myths Associated With Selecting Standalone Screens and a New Methodology for Sand-Control Applications by Rajesh A. Chanpura, Schlumberger, et al.
SPE 158371 Workflow To Evaluate Maximum Allowable Treating Pressures, Tubing Movement, and Tubular Limits for Deepwater Subsea and Dry-Tree Frac Packs by Marshal Strobel, Halliburton, et al.
SPE 165206 Significant Increase in Sand-Control Reliability of Openhole-Gravel-Pack Completions in ACG Field, Azerbaijan by Yoliandri Susilo, BP, et al.
Benchmark Helps Select Best Technique for Sand Control in Field Development
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16449, ’Production-Integrated Sand-Control Benchmark for Field Development,’ by Keng Seng Chan, SPE, Danny Chong, SPE, Rahim Masoudi, SPE, Mohamad B. Othman, SPE, and Norbashinatun Salmi Bt M. Nordin, Petronas, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
This paper shares the engineering approach used to determine where and when sand control was needed in offshore Malaysia on the basis of geomechanical sand-free critical-drawdown-pressure (CDP) evaluation for the selected well type, configuration, and completion. The decision to implement a proper method of sand control can be made by comparing the CDP with the minimum drawdown pressure (MDP) required to meet the target production rate. Sand-control-method selection was based not only on the sand-particle-size distribution, well life, and mode of well production but also on maximizing oil and gas recovery per well.
Introduction
The challenge in Malaysia was to design and implement a sand-control completion that could maximize well productivity with a stable wellbore under perceivable changing offshore production conditions implemented at the lowest cost.
The objectives of setting up the sand-control benchmark for the Malaysian field were
To reduce the sand-control completion costs by greater than 50%
To drive a sand-control well-design culture change for developing cost-effective well completions for sandstone reservoirs
To determine selectively where, when, and what sand control is needed in the developing reservoirs
To enable well-placement and reservoir-penetration-trajectory design to maximize sand-free-production drawdown pressure
To optimize the use of expensive sand-control methods
To estimate sand critical erosion pressure drawdown
Fig. 1 shows a carefully developed workflow.
Maximizing CDP
For a well designed to penetrate target reservoir sand, the sand-free CDP should be evaluated for the entire potential producing interval following the designed reservoir-penetration trajectory. Because the geomechanical properties change with pore pressure, this evaluation must be conducted for the whole life cycle.
For cased-hole completion, perforation orientation and phase angle can be optimized to increase the CDP. More effectively, CDP can also be increased by increasing well inclination for the same sand.
In some sands, the CDP can be affected strongly by water production. After water breakthrough, the rock strength and friction angle that affect sand consolidation and stability of sand structure at and near the wellbore may be dramatically reduced. Moreover, when formation sands contain significantly high amounts of water-reactive shale, the whole wellbore can collapse. CDP can then become very small, or even zero. High pressure drawdown could cause wellbore and even completion mechanical failure.
Comments: OPEC Turns 50
Authors: Donnelly John 
Published: February 2015

Editor's column
Fifty years ago, the heads of state of five countries—Saudi Arabia, Iran, Iraq, Kuwait, and Venezuela—signed an agreement in Baghdad that would significantly change the way oil is produced, priced, and traded. In a celebration marking OPEC’s half-century, the organization claimed that, despite its obituary having been written numerous times over the years, it had succeeded in achieving its original pledge to “stabilize oil prices in international oil markets with a view to eliminating harmful and unnecessary fluctuations.”
Said current OPEC Secretary General Abdalla Salem El-Badri: “The 50 years have seen various ups and downs, but the organization has remained true to its original goals of safeguarding the interests of its member countries, securing a steady income to producing countries, ensuring efficient and regular supply of petroleum to consumers, and a fair return to investors at fair and acceptable prices.”
OPEC may not dominate headlines like it did during the 1970s’ oil embargoes that quickly got the consumption-rich West’s attention, but it remains relevant and will continue to play a leading role in the oil market in the future. Last month, the organization approved a new Long-Term Strategy, its first in 5 years, in the face of a changing oil outlook. The group also agreed to hold its production steady, leaving output quotas unchanged since December 2008. Then, OPEC announced the last in a series of production cuts designed to revive oil prices that had dropped from USD 140/bbl to USD 34/bbl. The plan worked, with oil prices seemingly stable for now in the USD 70–80/bbl range despite global economic weakness. OPEC’s forecast now sees only a slight increase in global oil demand over the next 2 years, with growth coming from China and other developing countries.
The group will face challenges ahead and the country where the organization was created may prove to be its biggest headache. Iraq produces 2.3 million B/D now but has plans to rapidly ratchet up production to rival Saudi Arabia’s 8 million B/D and then eventually reach 12 million B/D. That is provided the country can rebuild its infrastructure, which severely limits such output gains, but the country just last month dramatically increased its estimate of proven oil reserves to 143.1 billion bbl, up from a previous 115 billion bbl. Any increase in Iraqi production would wrest market share from other OPEC producers, which could lead to infighting.
Challenges will also arise as the world looks more to natural gas and alternative fuels for energy. But hydrocarbons will still play a major role in energy supply for years to come, and OPEC member countries hold three-quarters of the globe’s reserves. Ian Skeet, a former Shell executive and author of a book on OPEC’s first 25 years, said about the future oil market then what is likely true today: “What can be said is that the international oil trade will continue, that the main supplier of that trade will be the countries which today form OPEC, and that Saudi Arabia will remain the single most important influence on oil price.”
Techbits: Drilling Technology Advances Reviewed in Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
In response to the fact that drilling engineers are constantly challenged to reduce well costs regardless of the economic climate, SPE held an Applied Technology Workshop (ATW) titled “Advances in Drilling Technology and Performance: Drilling the Limit” in Abu Dhabi earlier this year. The 2-day ATW brought more than 117 professionals from 39 international companies together to discuss the tools and techniques that have successfully reduced drilling capital expenditure and the gaps that still need to be addressed.
Improving Drilling Performance
Two technical sessions reviewed the industry’s progress in implementing the techniques and tools that enable full optimization of the drilling process. An ultimate aim of optimization—being able to drill all sections with one bit run—affords economic advantages as well as positive impacts on health, safety, and environment. The sessions provided several examples of where drilling optimization has been achieved.
Fred Florence of National Oilwell Varco discussed the new generation of drilling rigs powered by alternating current (AC). Florence said that new build trends are showing a shift to AC rigs, both on- and offshore, thanks to benefits that include increased top-drive motor speed and greater torque advantages over direct-current drives. In addition, AC rigs are inherently simpler machines, having lower weight and requiring less maintenance. They also lend themselves to easier automation, which improves performance and safety and gives process consistency with less risk.
A challenge Florence highlighted was that AC drives and automation add new components such as sensors, multiplexed signals, computers, networks, and variable-frequency drives, which require suitably trained and competent people. Those drilling contractors that are embracing AC rigs into their portfolios are seeing increased value due to reduced well costs and drilling time. Operators are also recognizing their value and are rewarding it through more contracts for AC rigs.
Tarek Mourad of Halliburton next reviewed the limitations of radioactive sources for various measurement-while-drilling technologies. Mourad cited telemetry limitations of current sources, which prevents a vast amount of data from being pulsed to the surface while drilling and limits a driller’s ability to make decisions that can optimize well placement and maximize the wellbore’s contact with the reservoir. He acknowledged that progress has been made in the areas of downhole analysis and computation, such as pressure sampling and imaging, and noted that work is progressing in the areas of increasing the speed of telemetry codes, electromagnetic-telemetry development, and wired drill pipe.
Other limitations include battery depletion, which is tied to the number of hours that the pumps are off and mud is not pumping, and limited memory size, which is based mainly on high sampling rates. Both of these limitations may necessitate extra trips downhole, which increases costs and safety risks.
Thirty Years of Gas-Shale Fracturing: What Have We Learned?
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133456, ’Thirty Years of Gas-Shale Fracturing: What Have We Learned?’ by George E. King, SPE, Apache Corporation, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.
Although high gas-flow rates from shales are a relatively recent phenomenon, the knowledge bases of shale-specific well completions and fracturing and shale-well operations have been growing for more than 3 decades, and shale-gas has been produced for more than 190 years. During the last decade, projected recovery of shale gas in place (GIP) has increased from approximately 2% to estimates of 50%, mainly through development and adaptation of technologies to fit shale-gas developments. This work surveyed more than 350 shale completion, fracturing, and operations publications, linking geosciences and engineering information together to relay learnings that will identify both intriguing information on selective opening and stabilizing of microfracture systems within the shales and new fields of endeavor needed to achieve the next level of shale-development advancement.
Introduction
The first lessons from this study were:
No two shales are alike. Shales vary areally and vertically within a trend, even along the wellbore.
Shale “fabric” differences, combined with in-situ stresses and geologic changes, often are sufficient to require stimulation changes within a single well to obtain best recovery.
Understanding and predicting shale-well performance require identification of a critical data set that must be collected to enable optimization of the completion and stimulation design.
There are no optimum, one-size-fits-all completion or stimulation designs for shale wells.
Although gas-shale-completions literature is developing rapidly, the history of gas-shale research offers a starting point that can help explain many phenomena seen in shales worldwide. Of the more than 350 references reviewed for this report and the 250 included, more than 60% date from 2007 or later, and learnings are increasing rapidly. The full-length paper seeks to define many of these advances and associates the references. This work is not about any single shale; rather, it focuses on characteristics within shale that can be addressed with completion, stimulation, and production technology to create opportunities for increasing gas recovery. The objective of this paper was to compile, explain, and link as much usable information as possible on the topics of completion, fracturing, and production behaviors.
From Bacteria to Barrels: Microbiology Having an Impact on Oil Fields
Authors: Rassenfoss Stephen 
Published: February 2015

The science behind the use of microbes to enhance oil recovery has advanced significantly, but it suffers from old associations.
After decades of trial and error, those working on microbial enhanced oil recovery have identified the “oil-eating” bacteria that laboratory tests suggest can change the properties in an oil reservoir, and know better how to put them to work. The increasing knowledge of the role microbial life plays in oil and gas reservoirs has also led to new approaches for controlling corrosion, managing bacterially produced hydrogen sulfide, and creating natural gas from coal.
(In this story, “eat” is used to describe the metabolic processes of bacteria. For instance, oil eating is more precisely hydrocarbon oxidizing.)
But the greatest potential payoff and the most debate come from the idea of microbes for enhanced oil recovery (MEOR). “There is a much greater understanding of what microbiology is doing in a reservoir” and how that can be used to produce more oil, said Stuart Page, chief executive officer of Glori Energy, a company that has staked its future of convincing the industry that microbes can be used to recover more oil.
MEOR is still often associated with promoters promising better oil production by dumping molasses into oil wells. “From a historical point of view, it is seen as snake oil,” Page said.
The image is darker than the history, which has been more hit and miss. For those in small companies, such as Glori, and big ones, such as Statoil, the challenge has been convincing experts in the field that promoting bacterial growth can be a consistent and effective way to produce more oil.
Work on using microbes to find oil goes back further than seismic imaging and the history of MEOR goes back more than 50 years.
Claude ZoBell, the scientist hired by the American Petroleum Institute who first discovered the microbiological ori-gins of oil, patented his MEOR concept in 1957. His approach involved introducing high-performing bacteria into a reservoir. It is one of many that has been tried and failed as people slowly came to better understand the exotic life in reservoirs.
Interest Grows In Asia Pacific Offshore Projects
Authors: Parshall Joel 
Published: February 2015

The vast horizon of the Asia Paciﬁc offshore region is a diverse and dynamic arena for oil and gas development, one of contrasts, complexities, and challenges. While there is no overriding theme such as the tremendous reserves of the Middle East, or bold new story as in the Brazilian pre-salt or North American tight shale, Asia Paciﬁc offshore is one of the world’s most active hydrocarbon provinces. More than 55% of the global oil and gas heavy lift vessel ﬂeet* operated in the region at some point during 2010, according to IHS’ ODS-Petrodata unit. Asia Paciﬁc offshore has the resources, commitment of its resource owners, and economic drivers to remain a major factor in global petroleum development for decades.
It is tempting to view the Asia Paciﬁc offshore as one large emerging market. Yet it is more than that. Countries such as China and Vietnam, which once were closed to most outside capital investment, are clearly open for business. Future oil and gas growth opportunities—though not necessarily the same for both countries—appear to have few limits. But then there is Indonesia, which certainly ranks as a mature province. A longtime oil exporter, it withdrew from OPEC in 2008 after becoming a net importer. Yet Indonesia is anything but a fading star. Projects such as Gendalo-Gehem and Abadi have technologically sophisticated development plans to meet major technical and commercial challenges, and the East Natuna project targets gigantic natural gas reserves—although accompanied by massive levels of CO2. Success in these and other projects could help Indonesia move closer to self-sufﬁciency in petroleum supply.
Challenges of many types face offshore projects throughout the Asia Paciﬁc region. Industry interest in the area is “quite strong,” according to Dylan Mair, director of Far East information and insight at IHS. “Historically, the big companies moved out of Asia and into exciting places like Brazil,” he said. “What we will probably see in the near future is these IOCs (international oil companies) moving back in. You’ve seen some movement already with the independents. The supermajors have also gotten involved in unconventional hydrocarbon plays where there is a need for external expertise to assist the efforts of the NOCs (national oil companies).”
Not all of the challenging projects are large. The critical need for petroleum to fuel regional growth adds an incentive to unlocking ways of commercializing smaller, often remote accumulations of gas.
Angus Rodger, Southeast Asia upstream analyst at Wood Mackenzie, described the region’s project environment thusly: “The low-hanging fruit is gone, and newer developments are located in more remote, frontier areas, deeper waters or require tackling more challenging geology. Usually, all of these challenges come together.”