bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Myth of the Oil Crisis
Authors: Mills Robin 
Published: February 2015

Guest editorial
"Our supplies of...oil and natural gas are being rapidly depleted, and many of the great fields are already exhausted." Not a warning from last year, when oil prices set a record of USD 147/bbl, but the words of pioneering conservationist Gifford Pinchot in 1910.
Fears of "peak oil" are nothing new. The economist William Jevons forecast in 1865 that falling coal resources threatened the British Empire. Predictions of imminent decline came from petroleum geologists in 1885, 1919, and 1956; from US President Jimmy Carter in 1977; and from the US government in 1980. A prominent "peak oiler," Colin Campbell, claimed in 1989 that oil output had peaked; another, Kenneth Deffeyes, put the peak date, rather precisely, at 16 December 2005. The high prices of 2008 seemed to give credibility to the idea that we had reached the physical limits of production. But now that prices have fallen, peak oil advocates raise a new alarm—that decline will be hastened by a lack of investment.
The opening years of the 21st century have been marked by milestones in the world of oil: the war in Iraq, the Shell reserves downgrade, hurricane Katrina, and the breaking of the once unthinkable USD 100/bbl barrier. Many have seized on these events as evidence that we are crossing the threshold of peak oil. Behind us, a century-and-a-half of abundant, cheap oil that fuelled industrial civilization and brought unprecedented prosperity to a fortunate global minority. Ahead of us, permanent declines in oil production, scarce and unaffordable energy, wars over dwindling resources, disastrous climate change, perhaps the collapse of modern society. But these ideas are based on misconceptions, flawed reasoning, and excessive pessimism. The world has abundant oil and gas for decades to come, geopolitical conflicts can be avoided by adroit policies, and we can learn to use hydrocarbons without unacceptable environmental damage.

Cheap Oil and Underinvestment
Recent high prices certainly seem to give some credibility to the idea that we are approaching some fundamental limit of oil resources. But we should remember how we arrived at this situation, because the culprit is not constraints on oil in the ground: it is the long 1986–98 period of cheap oil and underinvestment. Low prices decimated the oil industry, while the rise of energy-hungry new powers in Asia, combined with robust demand in the developed world and geopolitical upsets in major producers, stealthily ate up spare production capacity. As oil prices rose, investment increased, but much was consumed by cost inflation, while the most promising areas were mostly off-limits for political reasons. Supply growth was therefore disappointing. The inevitable result, perhaps amplified by speculation and market nervousness, was a sharp rise in the oil price.
Well-Intervention System Focuses on Better Measurement
Authors: McNicol Jim , Joppe Bart 
Published: February 2015

Technology Update
Until recently, most wells were of a relatively simple geometry, with the most complex having an initial vertical section followed by a straight tangent section that ended with a liner dropping into a vertical reservoir section. Workovers and wellbore-intervention operations in these well profiles were also comparatively simple, where the biggest challenge to evaluating the operation of service tools was overcoming sliding friction in the tangent section. Well profiles now are more complex and three-dimensional. In creating these complex well profiles, the drilling industry has developed some sophisticated and reliable downhole technologies to operate in extremely hostile physical environments.
The next phases of a well's life, however, present significant challenges in workover, cased-hole sidetracking, or any wellbore-intervention operation that has to manipulate service tools, whipstock systems, or fishing tools—often at great depth—in these same complex well profiles. Now the sophisticated drilling systems are missing, and the tool operators revert to relying on surface measurements of hookload, revolutions per minute (rpm), torque, etc. While these surface readings were reliable indicators for verifying a service tool's manipulation cycle position or condition decades ago, they are now often positively misleading. In these new well profiles, it can be difficult to ascertain, for instance, if a mill is rotating off-bottom, operating with optimum weight on mill (WOM), or crushing the cutters with excessive set-down weight. The more delicate the operation—retrieving a lightweight latch or fish for instance—the more difficult and risky the operation becomes.
With many of these intervention operations, the situation is further complicated by having to wait for a trip out of the hole to view the tool before the status of the downhole operation can be verified. Problems with performing intervention operations in this manner include technical risk (cost of failure), nonproductive time, and the cost of tripping in and out the hole to ascertain tool condition and job status.

New Intervention System
To try to counter these problems, a "smart" system has been developed for wellbore intervention. The new system aims to take accurate measurement of all static and dynamic downhole physical forces on intervention tools and transmit them to surface for real-time viewing on the rig floor. The system is integrated into current rig-data systems, such as Wellsite Information Transfer Specification, where the information can be forwarded on to offsite locations for evaluation. Decisions can also be made in real time, rather than having to wait for status-verification trips in and out the hole.
"Bright Star" Vietnam Moving into Unchartered Territory
Authors: Redden Jim 
Published: February 2015

Though it may not contain the known reserve base or production rates of neighboring Indonesia or Malaysia, Vietnam nonetheless has emerged as a "bright star" in Southeast Asia. So says Bob Fryklund, IHS vice president of global E&P critical information analysis, who adds that both proven reserves and daily production are expected to increase appreciably as the nation's eclectic group of operators move into more exotic plays.
"For years in Vietnam, everybody just worked a couple of basins. Now, with the country wide open, companies are working all these other unexplored basins. Traditionally, they tended to focus on just the basement play, which was all fractured, but some of it was carbonates, some of it was granitic-type rock, and some of it was volcanic rock. Now, clastic plays are starting to pan out and some of those will move out into the deeper water," he said.
To date, Vietnam has proven oil reserves of approximately 600 million bbl, which Fryklund predicts will reach 1 billion bbl with the fields that came on line in late 2008 and those scheduled to begin production this year and early next year. State operator PetroVietnam, however, says the results of earlier studies suggest that total offshore and onshore reserves could be as high as 6.5 to 8.5 billion bbl of oil and 75 to 100 Tcf of natural gas. Figures from the US Department of Energy's Energy Information Administration show that the nation's production rate, which is entirely from offshore, is 283,000 BOPD, compared to 943,000 and 601,000 BOPD for Indonesia and Malaysia, respectively.
Between existing fields, those expected to come on line over the next 2 years, and prospects for frontier plays, research analyst Business Monitor International predicts that Vietnam oil production will increase by 6.5% between 2008 and 2018, peaking at 400,000 BOPD next year. Gas production, it predicts, will rise from the estimated 10 billion m3 produced in 2008 to 27 billion m3 in 2018.
According to IHS, last year a total of 31 exploratory wells were spudded, of which 16 were classified as wildcats. The 2008 drilling campaign technically resulted in six discoveries, but the actual count is eight when the two wells spudded the previous year are taken into account.
"Vietnam certainly is not a giant in Southeast Asia like Indonesia and Malaysia, but its [reserves] are respectable and will be very important as the country continues to grow," Fryklund said.
Common Sense Economics for E&P Projects
Authors: Schulz Rodney 
Published: February 2015

Management
This article has two parts, both of which enhance established econometric paradigms and traditions commonly held by petroleum engineers. But instead of moving toward mathematical complexity, both parts move toward mathematical simplicity. The methods will add pieces to traditional econometric analysis, but the pieces are simple and easy to apply while adding significant value to the organization.

The Common Protocol
Traditionally, economic calculations utilized by petroleum engineers to evaluate and rank projects include internal rate of return (IRR) and net present value (NPV), with profit-ability index (PI) and payback possibly being considered as well. However, if one were to ask a petroleum engineer what metrics get discussed on a daily, monthly, or annual basis, the answer would likely be metrics such as achieving daily production targets and/or operating cost targets. Hence, we often have a significant disconnect between the metrics used to evaluate, qualify, and rank projects and the metrics that receive the most attention.
Additionally, if IRR, NPV, PI, and payback are discussed after a project's approval, it is likely to be in a post-audit a year or two out that receives little attention as long as minimal hurdles were reached. Because metrics such as daily production, operating costs, and staying within capital targets are the most discussed metrics, does it not make sense to evaluate projects on factors akin to the metrics most discussed?

A Common Sense Metric Set
One way to align project analysis and prioritization with daily, monthly, and annual objectives is to consider adding the following metrics to the traditional set of metrics:Initial incremental barrels of oil per day (BOPD) per dollar investedYear 1 average incremental BOPD per dollar investedReserves added per dollar investedOther similar metrics that agree with management objectives
Although the above metrics more directly align with the most commonly discussed objectives, one may argue that such metrics focus on the short term at the expense of the long term. However, taking an analogy from baseball yields another way to look at adding the above metrics.
Focusing on the above "common sense" metric set is like trying to win a baseball game by simply "moving the runners around the bases" instead of "swinging for the fence." This is particularly true when "swinging for the fence" requires one to make multiyear assumptions on things such as production, prices, operating costs, and tax-rate/government-intervention issues. In contrast, the common sense metric set is like moving the business forward one measurable step at a time.
Santos Basin Presalt-Reservoirs Development
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19953, "Santos Basin's Pre-Salt Reservoirs Development - The Way Ahead," by J.M.F. Filho, SPE, A.C.C. Pinto, SPE, and A.S. de Almeida, SPE, Petrobras, originally prepared for the 2009 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed.
The full-length paper describes the current studies for the future development of the presalt reservoirs in the Santos basin presalt cluster in deepwater offshore Brazil. Development of the area is divided into three phases. The first phase is a dynamic information-gathering phase comprising extended well tests and production pilots. The second phase, extending to 2017, will comprise conventional subsea completion systems. The third phase will consider nonconventional solutions.

Introduction
The area known as the presalt cluster, in the Santos basin, is in ultradeep water between 1900 and 2400 m, approximately 290 km offshore the Rio de Janeiro coast in southeast Brazil. Fig. 1 shows the main blocks of the presalt cluster, currently in the appraisal-plan phase.
At the beginning of the current century, the "cluster blocks" in the Santos basin were considered one of the most important exploration frontiers of the Brazilian continental shelf, given the size of the structures and the perfect seal created by the salt layer. In 2002, as the operator of different consortia, Petrobras obtained, through a bid process, the concession to explore several blocks in the Santos basin area. The first location, known as Parati (RJS-617), was approved in March 2004. At that time, just two wells had been drilled in the proximal portion of the basin, having crossed thick intervals of the presalt section. The existence of source rocks with characteristics similar to those found in the Campos basin was inferred through geochemical correlations, but there was significant uncertainty regarding the maturation, migration, and volumes that could have been generated and trapped. Despite these uncertainties, the most important risks associated with the locations were related to the existence and quality of the reservoirs. The Parati location was intended to test the stratigraphic traps in multiple objectives in the post-salt section and, additionally, to test a domic structure in the presalt. The sandstone reservoirs above the salt contained water, and the decision was made to go ahead with the well. After drilling 500 m of basalt, with several operational problems, the well drilling stopped at 7600 m true vertical depth subsea (TVDSS). Gas condensate was found in reservoirs of the presalt, confirming the presence of a petroleum system in the area, stimulating the drilling of RJS-628 in the presalt, which resulted in the Tupi discovery.
Effect of Salinity on Wettability Alteration of Porous Media From Liquid-Wetting to Intermediate Gas-Wetting
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121724, "Effect of Salinity on Wettability Alteration of Porous Media From Liquid-Wetting to Intermediate Gas- Wetting," by Stanley Wu, SPE, and Abbas Firoozabadi, SPE, Reservoir Engineering Research Institute, prepared for the 2009 SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 20–22 April. The paper has not been peer reviewed.
The synergetic effect of salinity and fluorochemicals on wettability alteration from water-wetting to intermediate gas-wetting was studied. NaCl salinity increased water-wetting when a core was saturated with brine. NaCl also reduced absolute gas permeability. CaCl2 salinity had a minor effect on permeability. NaCl, KCl, and CaCl2 brines have an adverse effect on wettability alteration.

Introduction
A reduction in effective gas permeability, observed in tight formations and in low-permeability gas reservoirs, often is attributed to water blocking and condensate accumulation. Water blocking is induced by the injection of water during hydraulic fracturing. Condensate accumulates at the wellbore as the pressure drops below the dewpoint pressure. A major factor of liquid retention in a rock is the liquid's low mobility because of strong liquid-wetting. By altering the wettability of the rock from liquid-wetting to intermediate gas-wetting, an increase in liquid mobility can be achieved resulting in a higher rate of gas production.
One concern about the salinity in chemical treatment is that the dissociated ions may destroy the stability of chemical polymers, resulting in colloidal coagulation leading to permeability reduction. The alcohols, which often are used as a solvent for chemical solutions to reduce gas-hydrate formation in drilling and production operations, have a significant and adverse effect on the solubility of salts, increasing the risk of salt deposition. An understanding of the effect of salinity and initial liquid saturation on chemical treatment is necessary for effective design and implementation of wettability-alteration strategies in complex systems. This study reported the gas absolute-permeability and gas/water effective-permeability data before and after treatment with fluorinated polymeric surfactants in isopropanol (IPA) solutions.

Experiments
Wettability alteration was carried out by injecting a chemical solution into Berea and reservoir-sandstone cores and aging them at high temperature and pressure. Treatment conditions were analyzed by varying the fluids used in initial saturation and pretreatment process before chemical injection. The effectiveness of chemical treatment was evaluated by measuring gas/liquid/rock three-phase contact angle, liquid saturation in imbibition tests, gas mobility in single-phase gas flow, and liquid mobility in two-phase gas/liquid flow.
CT Fracturing Method With Downhole Mixing Designed To Optimize Shale Completions
Authors: McNeil Fraser 
Published: February 2015

Technology Update
The challenge in recovering hydrocarbons from shale is the low permeability, making cost-effective fracture stimulation treatments essential to economic production. Technology advances and improved operational efficiency have made shale production around the globe far more viable. However, while the wells being completed are proving reasonably economic, are they achieving their full potential?
The most common method of multistage hydraulic fracturing in horizontal completions in the United States is the plug-and-perforate technique. This stems from the successful work performed in the Barnett Shale, starting in the late 1990s, where production results were deemed economic and the completion technique advanced toward a factory approach to improve operational efficiency. This technique involves running in hole with conventional guns to perforate multiple clusters in the first treatment interval, pulling out of hole, pumping a high-rate stimulation treatment, pumping a plug down to isolate the interval, then repeating until all intervals are stimulated. The reality of the plug-and-perforate process is that the efficiencies are achieved at the cost of stimulation effectiveness (reservoir access) and accompanied by a high risk of excessive downtime. Some of these disadvantages are:
Uncertainty of the number of fractures initiated within the clusters of perforations.
Uncertainty of proppant distribution along perforation clusters and across multiple fractures within the clusters, leading to potentially poor long-term production performance.
Underdesigned proppant schedules, intended to avoid screenout but that may not achieve adequate fracture conductivity.
Overflushing of the near-wellbore region, as a result of using pumpdown plugs.
The need to displace the entire casing volume before changes on surface will affect the treatment at the perforations.
Significant cost and time required to recover from unplanned events, such as screenout or stuck plugs.
Increased environmental footprint, personnel, and hydraulic horsepower required on location.
Relatively long completion time to bring the well on production
Added safety concern and potential downtime, both of which are inherent in running guns and pumping plugs.
Near-wellbore damage that can result from perforating conventionally (with explosive shaped charges).
To address deficiencies associated with the plug-and-perforate method, a fracturing technique deployed by means of coiled tubing (CT) has been developed by Halliburton that maximizes stimulated contact area (reservoir access) and reduces the risk of excessive downtime, thus improving operational efficiency.
Nanotechnology for Sale: The Once-Theoretical Becomes Practical
Authors: Rassenfoss Stephen 
Published: February 2015

The magic of nanotechnology is on display in the form of a dull silver ball created by Baker Hughes.
What looks like solid metal is a composite that is light enough to flow through a well, strong enough to stand up to the impact and pressure associated with opening a sleeve on a multistage fracturing job, and then disappear when it is done.
The company is making 1,500 of the balls each week and based on customer calls, it could sell a lot more, said James King, director of applications engineering for sales and operations support at Baker Oil Tools, US Land. The company plans to increase sales, and add new products, but the supply of the material used to make the balls is limited.
Producers see value in the balls because that expense is considerably less than the value of the production lost if a ball gets stuck during fracturing, blocking the flow from downhole. What looks like aluminum is a nanomaterial the company calls In-Tallic, which combines magnesium, aluminum, and other alloys. It is one of a class of materials called nano-structured metal composites that offer both strength and the ability to “dissolve” away under certain conditions.
The balls are far from the first product engineered to take advantage of the growing understanding of how to take the unique properties observed at nanoscale—generally 100 nanometers (nm) or less—and build those characteristics into products.
Tougher coatings using nanomaterials have been around for a while. In-Tallic balls stand out as an example of how nanotechnology can do things that otherwise would not be possible. The balls’ relatively short 18-month development period also shows what has been learned about engineering nanotechnology into products. “We are looking for ways to break that performance envelope,” said Gaurav Agrawal, director of enterprise research at Baker Hughes.
But it is not indicative of the time, effort, and barriers to acceptance more often faced by those creating products with nanotechnology for exploration and production (E&P).
“New generation materials can sell consumer products, but you cannot sell oilfield tools by saying it is nano,” said Jeff Bahr, chief executive officer (CEO) of NanoComposites, a company that uses carbon nanomaterials to develop polymers for uses such as high performance seals.
Oilfield buyers are not averse to nanotechnology, but the focus is on solving difficult problems, not on whether this hard-to-define technology was used. “Customers eyes glaze over when you start talking about how you used nanotechnology,” said Dore Rosenblum, CEO of Sub-One Technology, which makes pipe coatings.
One indication of the interest in applying nanotechnology is the list of oil companies doing research and development work. They include ConocoPhillips, Saudi Aramco, and Shell.