bluuebunny/crossref_metadata_2025_split huggingface dataset:
Emerging Frontiers: Trends in Capability Development
Authors: Spath Jeff 
Published: February 2015

President's column
This month I want to discuss what has recently become a very popular topic among both industry and academia—developing our talent. To weather the big crew change successfully, much of the solution surely involves how we instruct petroleum engineering students, how we train young professionals once they join the industry, and how we continually educate experienced engineers to ensure a sufficiently competent workforce. As the recent SBC O&G HR Benchmark Study (Schlumberger 2012) and the 2013 SPE Forum on Engineering Education (Chase 2013) both concluded, the issue isn’t just about the numbers (people shortage), it is about the skills (talent gap).
Digital Education
The way in which we educate at the university level is under revolutionary change in all disciplines, including the science, technology, engineering, and math subjects that feed our industry. Considering that the brick-and-mortar, lecturer-student model has been substantially the same since ancient Greece, it’s probably time for change. The incorporation of technology into this long-established method of teaching over the last few decades has begun to transform education, giving us online courses; “flip teaching,” where students watch video lectures at home and then work problems in class with more personalized guidance from teachers; and blended learning, which combines face-to-face classroom methods with computer-based studies. But the real disruptive innovation, the model that will really save students time and money and grant access to countless pupils in the most remote corners of the planet, is the creation and proliferation of massively online open courses (MOOCs) and teaching online qualified engaged students (TOQUES). They have the potential to transform undergraduate education.
TOQUES, in particular, will likely mark a tipping point: an inexpensive, online curriculum leading to a degree from an accredited institution. Instead of the massive, non-credentialed nature of the MOOCs trend, this new breed of degree programs emphasizes what universities do exceptionally well—teach degree-seeking students through engaging and thoughtful faculty-student interactions but in a truly diverse and global classroom. Unlike MOOCs, where anyone can participate, students must meet all qualifications for admission to the school. TOQUES are evolving and are becoming popular as they knit together education, entertainment, and social networking. Imagine how valuable this could be to our talent-deficient industry, allowing high-quality education to be location-independent and thus helping to solve many countries’ local content issues.
Industry Training
The transformation in teaching undergraduates has extended to industry training as well. Online courses are popular among young- and young-at-heart- professionals who must squeeze continuing education into already hectic schedules. Whether to obtain a graduate degree, a specific certification, or to simply keep up with advancing technologies, online is the way to go and MOOCs are becoming the preferred method.
Enhanced Hydrate Inhibition in an Alberta Gas Field
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90422, "Enhanced Hydrate Inhibition in Alberta Gas Field," by Dana Budd, EnCana Corp., and Danica Hurd, SPE, Marek Pakulski, SPE, and Thane D. Schaffer, SPE, BJ Chemical Services, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Operating gas wells in southern Alberta poses challenges. High bottomhole pressure in new wells, low bottomhole temperatures, and the Joule-Thompson expansion-cooling effect (which often lowers the gas-stream temperature below the brine freezing point) create conditions favorable for the formation of gas hydrates in wells and transportation pipelines. The problems are aggravated during cold winter months, when wells and pipelines have strong tendencies to plug with hydrates and ice. Systematic laboratory work was undertaken to explore synergistic effects between methanol and low-dosage hydrate inhibitors (LDHIs). A strong effect was discovered at a certain ratio of methanol and low-molecular-weight oligomer-type hydrate inhibitor.

Introduction
Gas hydrates form when water molecules crystallize around “guest” molecules. The water/guest crystallization process occurs at many combinations of temperature and pressure. Light hydrocarbons (methane to heptanes), nitrogen, carbon dioxide, and hydrogen sulfide are the guest molecules of interest to the natural-gas industry. Depending on pressure and gas composition, gas hydrates may build up at any place where water coexists with natural gas at temperatures as high as 30°C. Gas-transmission lines and new gas wells are particularly vulnerable to being blocked with hydrates.
Formation of gas hydrates can be eliminated or slowed by several methods. Thermodynamic prevention methods control or eliminate elements necessary for hydrate formation: the presence of hydrate-forming guest molecules, the presence of water, high pressure, or low temperature. Eliminating any one of these four factors from a system precludes the formation of hydrates. Unfortunately, elimination of these hydrate elements is often impractical or even impossible. For long subsea transmission lines, heating and insulating is a common mechanical solution to hydrate problems. Hydrates will not form if the gas/water system is kept at a temperature greater than the hydrate-formation temperature. Gas dehydration is another method of removing a hydrate component. However, in a practical field operation, water can be economically removed only to a certain vapor pressure, and residual water vapor always exists in a dry gas. Hydrate plugs in “dry” gas lines have been reported.
Adding chemicals to the gas/water streams is the most common method of preventing hydrate formation. Large amounts of alcohols, glycols, or salts are used. These additives thermodynamically destabilize hydrates and effectively lower the hydrate-formation temperature. They function by bonding to water molecules through hydrogen bonds or solvation.
Q&A with John Gibson (April 2006)
Authors: Gibson John , Donnelly John 
Published: February 2015

You have been with Paradigm now since April 2005. What changes have occurred at the company since then?
The first three or four months I was here, I was just a director. Then I began to get more excited about what was possible here, and I migrated to being Chairman, then Executive Chairman, and then Executive Chairman and CEO. So I have been in that role about 6 months. What really excited me about the company is that we have tremendous researchers, great scientific products, and an opportunity to make a real difference in the industry with our technology.
The owner, the employees, and I all believe that there is a lot of opportunity for Paradigm, and we have organized ourselves to take advantage of that opportunity. We have made a lot of changes, all in light of trying to grow the company to become the number one provider of high-end tools in the industry. We have brought in a tremendous executive team over the last year. We brought in new sales leadership, marketing and financial leadership, and development leadership. We have made a tremendous number of changes, but at the same time, we had a record quarter for software in the fourth quarter. So it is a case where we think we have taken the wings off the airplane and gotten them back on while in flight without doing any damage to the passengers.
What are Paradigm's leading-edge technologies?
The industry has tremendous data-management solutions for corporate data management that are already in existence, and we see our competitors doing a very good job of supporting multiclient data access. We also see tremendous offerings from competitors in reservoir simulation, and fluid flow and simulation is an area already covered. So you ask yourself, "What is it that really needs focus in the industry?" And that is what Paradigm's strength is. I think that over the next 10 years, you are going to see tremendous advances in geophysics and petrophysics coming together. It is taking microdata at the borehole scale and combining it with macrodata such as seismic and making sure that you have the right correlation and the right attribute model to carry into reservoir characterization. So we are integrating petrophysics and geophysics, which really gives us a leadership position in rock and fluid interpretation.
What is Paradigm's growth strategy?
The industry's move toward optimizing production means that petrophysics becomes a real driver in every decision on every desktop, and we have a leadership position in petrophysics. And when you leverage it with the geophysics, you give the petrophysicists the ability to see across the whole reservoir and the geophysicists the opportunity to incorporate rock and fluid analysis from the borehole. As the industry tries to enhance recovery, to get another 8% or 20% or 2%, it is those two disciplines combined on the front end for interpretation of the rock and fluids in their spatial positions and how they are changing dynamically over time that is really going to bring all of the value in the industry. Our growth will be a result of that becoming the focus.
Overview: Offshore Drilling and Completion (April 2007)
Authors: Gazaniol Didier 
Published: February 2015

Just flying over the North Sea, from Stavanger to Aberdeen, is definitely an interesting time to contemplate what the future of offshore drilling could be. Not that long ago, this so-called mature region was seen as declining, and drilling activity was slowly decreasing. In recent months, anyone trying to find an available offshore rig there (as in many other places indeed) knows that this vision of decline must be put aside, and for a long time, he/she will be very cautious with a prognosis about the future.
One thing that probably will remain is the pressure on drilling engineers and drilling teams as a whole to control, or at least mitigate, well costs. Several methods can be envisaged, which might be very different.
Of course, the market could be the first mitigating agent when a new equilibrium point will be reached. But does this industry really function on equilibrium points? And, for instance, is there any ceiling or minimum for deep-offshore-rig rates?
A first means could be to increase pressure on rig efficiency. We have been continuously and successfully improving technology, rig automation, and rig-time management for years. Still, there certainly is room for such improvements, and maybe a stopwatch will be the first driller's tool.
Another means is, of course, based on reducing our needs to the minimum. Even though this method has not always (or not yet) been successful from a business point of view (for instance, the slender-well concept), there are still interesting concepts that someday could introduce real breakthroughs. Some "drilling-from-the-mudline" concepts are probably among them, and the current mood for small-diameter drilling could be part of their success.
Eventually, beyond these cost challenges, new technical challenges also will have to be addressed. Our desire for fossil fuels will lead us to envisage producing such difficult reservoirs that, today, are often produced only onshore (e.g., heavy oils, tight reservoirs, and smaller accumulations). These challenges might once more put pressure on well costs so that, in the end, we may still be running after market equilibrium for a long time.
Offshore Drilling and Completion additional reading available at the SPE eLibrary: www.spe.org
SPE 101080 "Design and Performance Evaluation of an Ultradeepwater Subsea Blowout-Preventor Control System Using Shape-Memory Alloy Actuators" by N. Ma, U. of Houston, et al.
SPE 98894 "Large-Scale Feasibility Determination of Storing and Transporting a Cement Slurry Below Deck Under Maritime Conditions" by D. Doherty, SPE, BJ Services, et al.
SPE 99005 "First Hyperstatic Riser Joint Field Tested for Deep Offshore Drilling" by Y. Poirette, SPE, Inst. Français du Pétrole, et al.
SPE 105649 "CIDS to Orlan: Transformation and Startup of Sakhalin's Ice-Resistant Drilling Platform" by A.M. Higgins, SPE, ExxonMobil Development Co., et al.
Steam Injection in Fractured Carbonate Reservoirs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102186, "The Physics of Steam Injection in Fractured Carbonate Reservoirs: Engineering Development Options That Minimize Risk," by G.T. Shahin Jr., SPE, Shell E&P Technology; R. Moosa, SPE, PDO; and B. Kharusi and G. Chilek, Shell E&P Technology, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
The economic success of the Qarn Alam project depends on the ability to predict steam requirements and oil production. Two key oil-production mechanisms are heat transport through the fractures and into the matrix and gas-cap generation resulting from thermal volatilization of the oil. The process mechanisms involved in thermally assisted gas/oil gravity drainage (TAGOGD) were validated through laboratory experiments, while the field-forecast model results were validated by history matching pilot-performance data.

Introduction
The Qarn Alam field was first brought on production in 1975. When the field came on stream, the net oil production peaked at 6000 m3/d, despite the high oil viscosity. Water breakthrough followed rapidly, and by 1978, net oil production declined and remained low thereafter. During the initial peak in oil production, the oil contained in the highly permeable and pervasive network of fractures was produced and replaced mostly by formation water. After this period, a rim of oil remained, separating the newly formed fracture water/oil contact (WOC) and the newly formed fracture gas/oil contact (GOC). Under primary production, the reservoir produces on average approximately 100 m3/d of 16°API oil, at a 10 m3/m3 gas/oil ratio (GOR).
The purpose of TAGOGD in Qarn Alam is to develop additional oil by increasing the field recovery from 4% under isothermal gas/oil gravity drainage (GOGD) to 27% of original oil in place. TAGOGD is a novel enhanced-oil-recovery development concept that has as yet no full-field analog. Despite the lack of commercial analogs, several field trials have occurred on a pilot scale. Isothermal GOGD in this viscous (220 cp)-oil reservoir is economically unattractive because of the low oil mobility. Reservoir heating by steam injection significantly lowers the oil viscosity to approximately 2 cp, increases the gas cap as a result of thermal vaporization of the oil, and increases the GOGD rate by a factor of approximately 60. This development concept has been piloted in the Qarn Alam field and was found to be economically attractive. The attractiveness of the concept stems from the fact that the dense fracture spacing in the reservoir effectively distributes the steam and is a conduit to collect the oil in the oil rim. This type of development requires significantly fewer wells than an equivalent conventional steamflood.
Intelligently Using Intelligent Completions
Authors: Schorn Patrick 
Published: February 2015

Management
Oil and gas producers and service companies have long been committed to recovering more hydrocarbons from fewer wells. This presents a significant challenge, and most in our industry will agree that innovative application of technology is key to addressing it. Today, however, the challenge is even more daunting: to produce more complex hydrocarbon resources economically while continuing to increase ultimate recovery.
In the past, a well's longevity could be prolonged by plugging it back and recompleting it in a shallower pay zone, continuing until all zones had watered out and the well was abandoned. However, engineers realized that in spite of their best attempts, recovery factors averaged only 30%, and often their response was to drill more wells.
Engineers sought new ways to improve recovery while drilling fewer wells using geophysical and reservoir information to guide well placement. More accurate, higher-resolution data reduced interpretation ambiguities and decision risk, and advances in drilling technology allowed wells to be steered into the most prolific portions of the reservoir. Most significantly, the shift from analog to digital data recording enabled integration of information from separate sources. This integration improved knowledge and allowed full field simulation, which in turn resulted in better reservoir understanding and more efficient field development plans.

From Knowing to Doing
Over time, several techniques have been employed to maximize early production and optimize financial returns. However, in the current environment, production rates alone do not define a good project.
Economically improving recovery is perceived as more difficult to achieve than just increasing production. Recovery is highly dependent on completion technology and reservoir management. Completion technology and reservoir management are more likely to succeed when applied on a fieldwide basis, and they both require substantial upfront engineering and investment. Despite the technical challenges, increasing recovery economically is essential to bringing the industry to a new level of success.
As we encounter more complex reservoirs, requiring multiple-zone completions, it is critical to have the capability to modify the downhole completion as production parameters change over the life of the well. The types of completions that can be modified to improve recovery are intelligent completions—combinations of downhole sensors and actuators, plus the software and systems integration to monitor and control individual sections of a well remotely.
In the first applications of intelligent completions, the focus was on single-well flow-control valves with limited monitoring. The economics of such technology limited its use to complex, often subsea, wells with high productivity. Over the course of a decade, however, about 1,200 zones now are producing through intelligent completions.
Comments: Mexico's Challenge
Authors: Donnelly John 
Published: February 2015

Editor's column
Four months after major oil reform was approved in Mexico, the country's oil industry is struggling. Oil production in the country—one of the world's top producers and suppliers—peaked in 2003 at 3.46 million BOPD, with the heralded Cantarell field supplying approximately two-thirds of that total. But by February of this year, production had declined by almost a third to 2.64 million BOPD with Cantarell's share dropping to just over 700,000 BOPD.
Located in the Gulf of Campeche, Cantarell is one of the largest oil fields in the world and has been the backbone of Mexico's production strength. Output at the field began in 1979 but gradually declined because of falling reservoir pressure. In 1997, state oil company Pemex began a massive nitrogen-injection project designed to maintain reservoir pressure and reverse the decline. The plan worked and, by 2004, output at the field had doubled to more than 2 million BOPD. But the field soon began to decline again and its faster-than-expected drop may be irreversible. Now, Pemex, as well as the government, which relies heavily on oil revenue, are searching for ways to develop new resources to compensate.
Pemex is seeking outside financing to fund an ambitious investment program. It wants to spend a total of USD 19 billion this year, primarily on upstream exploration and development, and is hoping to maintain overall country production at 2.75 million BOPD and gas output at 65 billion cubic ft/D. Its most promising oil targets are the offshore Ku Maloob Zaap field, where output has grown to 800,000 BOPD—now Mexico's largest field—and Chicontepec, a complex onshore field that currently produces only 145,000 BOPD but has great potential. Pemex plans to drill 1,000 new wells at Chicontepec this year, and also plans to explore more in the deepwater Gulf of Mexico.
Upstream development and Pemex's operations have been hamstrung by the country's constitution, which has all but prohibited private investment in the oil sector since 1938 when the oil industry was nationalized. Significant reforms are now taking place but their success depends on how, and how quickly, the reforms are implemented and whether they will be enough to attract outside investment.
After considerable debate, the government made several key regulatory changes last November, including provisions that reduce Pemex's tax burden, allow the company more oversight of its budget, enhance its ability to raise debt, and give it more flexibility in licensing terms. In addition, four independent members will join Pemex's board, which will create new contract models. Analysts believe that service companies and local firms will find the changes promising, but international oil companies may need more enticement before they invest in Mexico's upstream. Already, the Mexican state oil company has awarded contracts totaling more than USD 5.39 billion this year, a boost for service companies during a year when many companies are making major spending cuts.
Fiber-Optic DTS Flow Profiling Installed in Advanced MRC Well
Authors: Kluth Richard , Naldrett Garth 
Published: February 2015

Technology Update
The current decline in crude oil prices has created major interest in methods that significantly reduce overhead and improve efficiency in operations. Distributed temperature sensing (DTS), used for advanced, in-well permanent monitoring, is a technology that can deliver on both of these objectives.
DTS has demonstrated long-term reliability, high performance, and application benefit in a range of production- and injection-well types. An area of particular interest is the application of monitoring in horizontal and advanced well completions. While allowing significant improvements in production and reservoir depletion, these wells have caused data-gathering disruptions for the operators. In particular, the options for performing well logging are much reduced, and the costs of performing a production log extremely high. These factors are related to the costs of both the more advanced horizontal well-logging tools and the more expensive logging methods—such as coiled-tubing and tracker systems—used to convey these tools into the wellbore.
DTS allows this monitoring gap to be closed. In line with advancements in this technology, Sensornet and FloQuest have developed a real-time digital flow-profiling system, which aids increased production, reduces operating costs and improves recovery. Digital flow profiling with DTS is used to determine distributed flow-allocation profiles in production and injection wells. The system combines DTS fiber-optic technology with software modeling and data interpretation (Figs. 1a and b).
The combination of the two technologies enables accurate location of fluid entry points across an entire reservoir. The result is a permanently installed system providing continuous data similar to that obtained from a production-logging tool (PLT), even before the completion is locked down.
The key to obtaining accurate and reliable flow information across the reservoir interval by means of DTS data relies on two principal factors. First, the DTS system must be able to detect very fine temperature changes. (The DTS system discussed here can measure temperature changes of less than 0.01°C at all points along the reservoir.) Second, to extract valuable information from the temperature data, it is essential to combine it with information on the geology, reservoir fluids, and the completion. In the system under discussion, this information is obtained by means of interpreting data from software models.