bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Education Forum: It Is More About Head Content Than Head Count
Authors: JPT staff _ 
Published: February 2015

Techbits
SPE recently sponsored a forum on the need to ensure an appropriately educated upstream engineering workforce in 2020 and beyond. Titled 2020 Foresight: Ensuring Excellence in Petroleum Engineering Education, the session took place in August in Idaho. Attendees concluded that the current petroleum engineering educational systems are not sustainable to produce the talent that the oil and gas industry will need in 2020 unless the industry and academia make this issue a priority and collaborate on ways to resolve the anticipated underlying gaps.
The idea for the forum grew out of a series of colloquia on petroleum engineering education dating back to 1991. Past colloquia were geared toward aligning education with meeting the industry’s needs, as well as developing continuous improvement processes and refining program assessment methods. Over time, the SPE Board of Directors has become concerned about potentially significant problems developing in the global petroleum engineering education system and the ability of the system to sustainably produce the talent that industry will need in the next decade. The SPE Board sanctioned the forum in an effort to bring academia and industry representatives together to collaborate and propose solutions to the issues.
Forty-seven participants from 10 countries on five continents representing academia (57%) and industry (43%) spent a week analyzing the current and future engineering resourcing environments. The group identified the following key issues to help define the business imperative toward making petroleum engineering education more sustainable.
Although regional pressures exist near term in sub-Saharan Africa, the United States, and the Middle East/North Africa region, there may be a talent gap rather than a people shortage in the industry by 2020. Gaps in both technical and nontechnical skills were identified as barriers for an effective petroleum engineer in the future. This may make a degree in petroleum engineering with relevant course work even more valuable to some companies, where new petroleum engineering hires can contribute earlier than graduates from other engineering disciplines without the domain-specific training.
Petroleum engineering faculty demographics are of significant concern and the feeder pool of PhDs being attracted to academia is currently inadequate. The number of current faculty vacancies was cited as a leading indicator. For example, nearly two-thirds of the US faculty will qualify for retirement in the next 10 years. Although demographic data was only available for US petroleum engineering departments, faculty from other regions attending the forum anecdotally agreed that the situations in their countries or regions were similar or more challenging.
A root cause of the faculty shortage is that petroleum engineering PhD faculty compensation and benefit packages are not competitive with industry packages.
Cracking the Cline: A New Shale Play Develops in the Permian Basin
Authors: Jacobs Trent 
Published: February 2015

Cline Shale
Early in its development, the Cline shale was hyped as the next Eagle Ford or Bakken with more oil and gas than they have combined.
The lofty projections of the Cline shale’s potential, located in west Texas on the eastern side of the Permian Basin, were extrapolated from information presented by Devon Energy to financial analysts in April 2012.
At that time, the company’s data regarding the emerging play suggested the possibility that as much as 3.6 billion BOE lie trapped within Devon’s 500,000 acres of Cline shale. Analysts looking for North America’s next major unconventional resource then calculated that the entire formation, roughly 140 miles long and 70 miles wide, held between 30 and 35 billion BOE, which would make it one of the largest discoveries in the world.
That hasty estimate did not take into account how much of the potentially mammoth resource could be economically recoverable. Devon said it is not far enough along in its Cline shale operations to share information.
Other operators in the Cline have encountered issues that make producing from the formation a challenge, such as heavy-clay content, and as a result, the production quality is not consistent across the play.
“There was a lot of optimism up front,” said Benjamin Shattuck, an upstream analyst at Wood Mackenzie in Houston. He said that the variability in initial production rates among the handful of operators drilling horizontal wells in the Cline has revealed the best acreage to be in the west Texas counties of Glasscock and along the western side of Sterling. “That doesn’t mean that there have not been decent results outside of that area,” Shattuck said, “but I think some of the excitement has been tempered a little bit.”
Tempered perhaps, but not all the way gone. The operators with early success in the Cline and even those facing setbacks are moving forward on their investments in drilling the shale and building up the infrastructure needed to support field development for years to come (Table 1). What remains to be determined is whether the Cline will be a uniform and commercially competitive formation across the vast area that it encompasses, or be limited to small pockets in which the shale is conducive to production.
Three-Finger Black Shale
Before it came to be known as the Cline, the nickname for the formation was the “Three-Finger Black Shale” because of its rich darkness seen in core samples, and the distinctive resistivity peaks identifying its location during vertical well logging (Fig. 1). Operators have drilled more than 1,500 vertical wells through the formation in the past several years. The vertical drilling programs provided oil companies with the geological and petrophysical data that they are using today to understand and successfully deplete the formation of hydrocarbons by drilling into it horizontally.
Challenges and Solutions Surface at SPE Annual Conference
Authors: JPT staff _ 
Published: February 2015

Conference review
The frontiers of deepwater and pre-salt reservoirs garnered much attention at the 2013 SPE Annual Technical Conference and Exhibition (ATCE) held in New Orleans in October. The conference brought together 12,028 oil and gas professionals from around the world.
“This year’s ATCE ranked as the highest attended since 1999,” said Egbert Imomoh, 2013 SPE President. “The event capped a year of tremendous success for SPE with a growing global membership, increased technical content, and strong financial performance.”
The conference received 1,773 technical paper proposals this year, compared with slightly less than 1,500 a year ago. The 2013 program of 52 sessions included more than 300 technical papers and 67 ePoster presentations. With panel sessions, there were more than 400 presentations in total.
Opening Session
Discussion at the opening general session revolved around safety, technology, and the cost of deepwater oil and gas projects. A government official and four industry top executives made up the panel for the session titled “Deepwater Exploration and Development—Challenging the Limits.”
Lars Herbst, Gulf of Mexico (GOM) regional director for the United States Bureau of Safety and Environmental Enforcement (BSEE), described GOM deepwater drilling rig activity as very robust, having recovered from the post-Macondo drilling moratorium. Seventeen new deepwater rigs are expected to enter the GOM under long-term contracts by the first quarter of 2015.
“So, to begin, we are talking about opportunity for drilling. There is plenty of opportunity,” he said.
In GOM deepwater development, 10 projects have been sanctioned and 10 discoveries are in various stages of appraisal, Herbst said. The deepwater activity is “going to require not only new technology but increasingly qualified employees,” Herbst said. “We often talk about competency, but it is going to be capacity as well.”
The BSEE official discussed deepwater challenges and risks. “There is a difference,” Herbst said. “A risk is something that has the capability of causing harm or injury, and a challenge is something that hopefully motivates us to move the status quo.” An item can move from one category to the other, he noted.
The challenges Herbst cited are high-pressure/high-temperature technology, improving blowout preventers (BOPs), enhanced oil recovery, and dual-gradient drilling, as well as workforce issues.
For risks, Herbst noted recent failures in small components, such as shackles and bolts. While no large incident occurred, “a small component can cause a major failure,” he said. There have also been numerous dynamic positioning failures in the past several years. In well control since Macondo, there have been shallow-water incidents and some of them “translate to deep water,” he said.
John Gremp, chairman and chief executive officer of FMC Technologies, put the industry’s deepwater needs in perspective.
Nanoemulsion-Enhanced Treatment of Oil-Contaminated Cuttings
Authors: Denney Dennis 
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper SPE 162401, ’Nanoemulsion-Enhanced Treatment of Oil-Contaminated Oil-Based Drill Solids,’ by Wasan Saphanuchart, SPE, Yoong Shang Loke, SPE, and Chun Hwa See, SPE, BCI Chemical Corporation, prepared for the 2012 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed.
When oil-based mud is used, the drilled formation solids (cuttings) are regarded as controlled or hazardous waste. As such, they can be disposed of in three ways: decontamination treatment followed by discharge into the sea, injection of the cuttings into the well, or transfer to a controlled hazardous-waste landfill. The lowest environmental effect for solids disposal, especially for offshore operation, is decontamination treatment followed by discharge. However, conventional decontamination technology exhibits limited efficiency in extracting oil from the drill solids.
Introduction
One function of drilling mud is a washing action to remove cuttings from the wellbore. The mud returns to the surface with entrained cuttings and, typically, flows through shale shakers, desanders, desilters, hydrocyclones, centrifuges, or other devices to separate the cuttings from the mud. Conventional decontamination technology yields an oil content in the treated cuttings of &gt;1% in the dried solids, which does not meet strict environmental regulations in many highly ecologically sensitive countries (e.g., the UK and North Sea countries). Apart from cuttings reinjection, all other treatment methods require land-based waste treatment.
Nanoemulsion technology can improve oil-removal efficiency by providing ultralow oil/water interfacial tension (IFT). Heavy- and light-oil extraction from the cuttings surface is enhanced. The cuttings-treatment process proposed in this paper can achieve oil content of &lt;1%.
Nanoemulsion
Nanoemulsions are clear and thermodynamically stable. In typical nanoemulsions, the droplet size ranges from 10 to 100 nm, which is much smaller than the wavelength of visible light. Hence, nanoemulsions generally are weak scatterers of light, making them transparent. Nanoemulsions can be formulated with a single phase or multiple phases. The IFT between the aqueous and hydrocarbon phases in nanoemulsion systems can be as low as 0.0001 mN/m, compared with an ordinary emulsion or macroemulsion (approximately 0.1 to 30 mN/m). A nanoemulsion might be a dispersion of water in oil or oil in water (in which the second solution is the dispersion medium or solvent). There may also be a bicontinuous structure in which both water and oil are continuous.
An Experimental Study of Liquid Loading of Vertical and Deviated Gas Wells
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164516, ’An Experimental Study on Liquid Loading of Vertical and Deviated Gas Wells,’ by G. Yuan, E. Pereyra, and C. Sarica, SPE, University of Tulsa, and Robert P. Sutton, Marathon Oil, prepared for the 2013 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, 23-26 March. The paper has not been peer reviewed.
An experimental study of liquid loading of gas wells has been conducted with air/water flow in a 3-in. pipe at well deviations of 0, 15, and 30° from vertical. A total of 131 tests have been carried out; differential-pressure gradient and liquid holdup were measured. Flow pattern was observed, and critical gas velocity, which defines the threshold for liquid accumulation in a well (commonly termed liquid loading), has been identified.
Introduction
During the production of gas wells, liquid loading is considered one of the most important production problems. Symptoms of liquid loading include liquid slugging at surface equipment, declining or erratic water- and gas-production rates, and dramatic changes in wellhead pressure. Left unchecked, the water accumulation in the well increases the backpressure against the reservoir and provides a damage mechanism by saturating the near-well region with water.
Critical gas velocity is the key parameter in describing liquid loading. There are three definitions of critical gas velocity used in the literature:
The minimum gas velocity at which the largest liquid droplets entrained in the gas core can be transported upward, as used in the criterion of Turner et al. (1969).
The gas velocity at which the flow pattern changes from annular flow to intermittent flow.
The gas velocity at which liquid film starts to move up the pipe wall continuously.
The Turner et al. criterion has been used widely in the industry to predict critical gas velocity for the past several decades. This criterion is based on a force balance on a single droplet entrained in the gas core. It was proposed that the gas well loads up when the entrained droplet moves downward, which is called droplet-flow reversal. Turner qualified the use of the model by stating that the velocity result should be increased by approximately 20% to ensure liquids do not accumulate in the well. The Turner et al. droplet model is based on a vertical configuration and does not include the influence of well deviation on critical gas velocity. This may explain the poor behavior of the Turner et al. model on field data from deviated wells.
The liquid-loading mechanism is still under debate. The majority of existing models are modifications of the Turner et al. droplet model, each with some degree of success in matching the field data. However, film-flow reversal now seems to be the main mechanism, on the basis of observations in the most recent experimental studies. This criterion is adopted in this study to describe the loading initiation in vertical and deviated wells.
Comments: Heroic Effort
Authors: Donnelly John 
Published: February 2015

Editor's column
The recent rescue of 33 miners in Chile was a textbook success story. Behind the scenes, the oil and gas industry and several SPE members played key and supporting roles in the humanitarian effort that mobilized the best drilling technology available and captured the world’s attention.
The miners, who were trapped nearly half a mile underground in the copper and gold mine for 68 days, were finally rescued in a complex and expensive operation. The Chilean government spared little expense in requesting help from drillers and other experts from more than a dozen countries, and industry was quick to offer assistance with equipment and personnel.
One SPE member who assisted in the rescue was Nestor Eduardo Ruiz, a former chairperson of the SPE Patgonia Section in Neuquen, Argentina, and a manager at Argentina’s Gyrodata. He was part of “plan C,” one of three simultaneous operations organized to pull the miners to safety. Eduardo, who has worked in the directional drilling industry for 24 years, said he was contacted by one of plan C’s leaders who knew him from the early days of his oil and gas career. His company, Gyrodata, had done business with Chilean state companies Enap and Sipetrol, helping to survey wells to determine accurate wellbore positioning.
“Needless to say, this was a big challenge for me and my company,” Eduardo said. “We could demonstrate our technology to direct and measure a well toward a tight objective in order to rescue 33 human lives. It was an incredible challenge.”
When plan B—the second of three operations devised for the rescue—started to open the hole that would eventually free the miners, plan C went into effect. They were able to reach their depth target despite the fact that it was an extremely hard rock to drill, he said. “We used tricone bits with inserts,” Eduardo said. “It is not an easy task to drill a 28-in.-diameter wellbore directionally from the surface. As the control of the trajectory was not easy to do, it was necessary to change to a 17½-in. hole diameter at 220 m. With more weight on the bit, control of the trajectory was more predictable.”
Eduardo said he relied on several SPE technical papers for guidance during the operation, as well as the advice of coworkers and SPE colleagues in Houston and Norway, including Rob Shoup, Jean Paul Lips, and Roger Ekseth. The company’s latest survey technology, the CAAT gyro tool, was used to measure the trajectory of the well. “The challenge for my company and for me was to provide the best wellbore position free of errors,” he said.
Numerous drilling companies, both energy and nonenergy related, were involved in the rescue, including Layne Energy, Geotec, Precision Drilling, and Center Rock. “All of the service companies and technology involved—the drilling rig, directional drilling, wireline, mud, bits, etc.—represented a tremendous effort and we all worked together from the beginning,” he said. “Our industry showed it cared and we tried very hard to deliver an escape route for the trapped miners, while minimizing their risk and the risk of the rescuers at the same time.”
Hydraulic Fracturing: History of an Enduring Technology
Authors: Montgomery Carl T. , Smith Michael B. 
Published: February 2015

Hydraulic Fracturing
Editor’s note: In 2006, SPE honored nine pioneers of the hydraulic fracturing industry as Legends of Hydraulic Fracturing. Claude E. Cooke Jr., Francis E. Dollarhide, Jacques L. Elbel, C. Robert Fast, Robert R. Hannah, Larry J. Harrington, Thomas K. Perkins, Mike Prats, and H.K. van Poollen were recognized as instrumental in developing new technologies and contributing to the advancement of the field through their roles as researchers, consultants, instructors, and authors of ground-breaking journal articles.
Following is an excerpt from SPE’s new Legends of Hydraulic Fracturing CDROM, which contains an extended overview of the history of the technology, list of more than 150 technical papers published by these industry legends, personal reflections from a number of the Legends and their colleagues, and historic photographs. For more information on the CDROM, please go to http://store.spe.org/Legendsof-Hydraulic-Fracturing-P433.aspx.
Since Stanolind Oil introduced hydraulic fracturing in 1949, close to 2.5 million fracture treatments have been performed worldwide. Some believe that approximately 60% of all wells drilled today are fractured. Fracture stimulation not only increases the production rate, but it is credited with adding to reserves—9 billion bbl of oil and more than 700 Tscf of gas added since 1949 to US reserves alone—which otherwise would have been uneconomical to develop. In addition, through accelerating production, net present value of reserves has increased.
Fracturing can be traced to the 1860s, when liquid (and later, solidiﬁed) nitroglycerin (NG) was used to stimulate shallow, hard rock wells in Pennsylvania, New York, Kentucky, and West Virginia. Although extremely hazardous, and often used illegally, NG was spectacularly successful for oil well “shooting.” The object of shooting a well was to break up, or rubblize, the oil-bearing formation to increase both initial flow and ultimate recovery of oil. This same fracturing principle was soon applied with equal effectiveness to water and gas wells.
In the 1930s, the idea of injecting a nonexplosive ﬂuid (acid) into the ground to stimulate a well began to be tried. The “pressure parting” phenomenon was recognized in well-acidizing operations as a means of creating a fracture that would not close completely because of acid etching. This would leave a flow channel to the well and enhance productivity. The phenomenon was conﬁrmed in the ﬁeld, not only with acid treatments, but also during water injection and squeeze-cementing operations.
Global Unconventional Gas - It Is There, But Is It Profitable?
Authors: Holditch Stephen A. , Madani HusamAdDeen 
Published: February 2015

Management
Gas reservoirs are often classified as conventional or unconventional. Conventional gas reservoirs are characterized by high permeability with the gas stored in sand or carbonate formations in pore spaces that are interconnected. A gas resource is generally considered conventional if it does not require a large stimulation treatment to be able to produce oil and gas at economic flow rates. An unconventional gas reservoir can be defined as a natural-gas reservoir that cannot be produced at economic flow rates or in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or multilateral wellbores (Holditch, 2006). The three most common types of unconventional gas resources are tight sands, coalbed methane, and gas shales.
Unconventional gas reservoirs are characterized by low permeability, in the microdarcy range (Fig. 1) or less. As the permeability deceases, the economic risk of developing the resource increases, and the investment required also increases because more wells have to be drilled to produce the reservoir, as each well recovers less gas per well than one can recover per well from a conventional reservoir.
The US Department of Energy’s (DOE’s) Energy Information Administration (EIA) defines the total natural-gas resource base as all of the gas that has ever been trapped inside the Earth, including the volumes that have already been produced. The part of the total natural-gas resource base that interests investors most, however, is the remaining natural gas waiting to be extracted. Research indicates the existence of large, unconventional gas reservoirs located throughout the world. Rogner (1997) estimated that there are 9,000 Tcf of original gas in place (OGIP) reserves in coalbed methane, 16,000 Tcf of OGIP in shale gas, and 7,400 Tcf of OGIP in tight gas sands around the world (Table 1).
Since Rogner published his paper, the oil and gas industry has discovered enormous volumes of natural gas in unconventional gas reservoirs in North American and in several other basins around the world. It is believed that the OGIP estimates in Table 1 are very conservative. The industry will be updating the values in Table 1 and it is expected that the values of OGIP will increase substantially.
With declining conventional gas reserves in the United States, unconventional gas reservoirs are emerging as critical energy sources to meet the increasing demand for energy. The US DOE April 2009 report, Modern Shale Gas Development in the United States: A Primer, stated that over the last decade, production from unconventional resources in the US has increased almost 65%, from 5.4 Tcf/yr in 1998 to 8.9 Tcf/yr in 2007. This increase in production indicates that approximately 46% of today’s US total gas production comes from unconventional resources (Navigant 2008).