bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovation: Innovative Drilling Operations
Authors: Imomoh Egbert 
Published: February 2015

President's column
The first wells used to search for oil were drilled more than 150 years ago. Since then, various innovations have been adopted and adapted to enable us to drill deeper and deeper wells, with longer and longer reach, and in ever-increasing water depths, resulting in access to oil and gas reserves that have fundamentally changed the world. We have encountered various challenges over the years, but by seeking new ways of getting the bit down to the depth required in a safe manner, our industry has allowed billions of barrels of oil and trillions of cubic feet of gas to be produced for industrial growth and development. Those first wells were drilled with very basic tools. The floaters of today, drilling in thousands of feet of water, are clearly far advanced from the early efforts, which used a steam engine powered by a wood-fired boiler.
Edwin Drake is famous for his pioneering drilling work, and as with most innovators, he met head on with potential failure when he drilled his first well. Drake encountered losses and potential hole collapse that would have prevented him from drilling to his planned total depth. He is reported to have driven a surface pipe and then proceeded to drill and reach into deeper horizons. This fundamental principle of isolation has served the industry well and forms the basic design of wells drilled today. However, innovation has permitted some operators to drill through surface sections that present swelling problems that lead to premature setting of surface pipe, which in turn lead to delays in drilling operations and increased well cost. Some operators have successfully applied innovative casing-while-drilling techniques, which use large pipes as the drilling string. This technique allows the operator to minimize exposure of the wellbore to the drilling fluids and reach surface setting depth as planned (SÁnchez, Houqani, Turki, and Cruz. 2012).
The history of drilling is rich with innovations. They are too many to cover in one column, but I think two are noteworthy: the advances that permitted drilling in deeper and deeper waters and the development of mud motors.
The early move away from land operations took place approximately 120 years ago when wells were drilled from platforms that were constructed on piles in fresh water and then on piers in various areas offshore the US. As explorers found prospects in deeper and deeper waters, new technology was needed to drill from barges, artificial islands, or concrete barges. Today’s jackups and semisubmersibles are a far departure from the rudimentary equipment used for early offshore drilling.
Comments: The Long-Term Outlook
Authors: Donnelly John 
Published: February 2015

Editor's column
Energy outlooks by companies, government agencies, and private industry groups identify long-term energy trends and develop projections on supply and demand based on factors such as technological advancement, population trends, the global economy, and policy issues. One of the most respected of these viewpoints comes annually from ExxonMobil, which last month updated its projections for the next 25-plus years in its “Outlook for Energy: A View to 2040.”
Although some of the trends are carry-overs from previous editions, the energy landscape has changed a lot over the past few years, most notably the growth in unconventional resources in North America. Here are some of the significant findings from the report:
Energy demand in developing nations will rise 65% by 2040, reflecting growing prosperity and expanding economies.
Greater demand in electricity and transportation fuel will help drive this increase.
Technology continues to allow for the development of once hard-to-produce energy resources, significantly expanding available supplies to meet global demand.
Oil will remain the top global fuel, as transportation use will contribute to gasoline and diesel demand. Demand for transportation fuel will stay flat in Europe and decline in North America, but it will grow dramatically in the rest of the world.
Natural gas will become the world’s second most used fuel during the period, overtaking coal.
ExxonMobil forecasts that global energy consumption will rise 35% by 2040, primarily in China and India. Demand in developed regions such as the United States, Canada, and Europe will largely remain unchanged or decline as they become more efficient in their energy use. Developed nations are forecast to generate 80% more economic output by 2040 compared with 2010, but will use the same amount of energy.
Another report released last month, by the US Energy Information Administration (EIA), predicts that growth in unconventional production will continue to have a huge effect on the US. The report forecasts US oil production increases of more than 200,000 B/D each year through 2019. In addition, the country will become an important supplier of natural gas globally as domestic production outpaces demand.
The US currently produces 6.5 million B/D of oil and that figure will rise to 7.5 million B/D by 2019, and will remain above 6 million B/D through 2040, according to the report. Most of the growth will come from onshore production, mainly from shale and other tight formations, the EIA said. US gas production will continue to out-strip domestic demand through 2020. The outlook sees world oil demand growing from the current 88 million B/D to 113 million B/D in 2040 because of strong consumption in China, India, Brazil, and other developing economies.
HT Stimulation Fluid Based On GLDA Meets Productivity, Environmental Need
Authors: Nasr-El-Din Hisham A. 
Published: February 2015

Technology Update
Industry operations are shifting toward high-temperature (HT) downhole set-tings, expensive tubular metallurgy, and extended reach wells, while health, safety, and environmental requirements become stricter. Consequently, conventional stimulation treatments, such as applications using hydrochloric acid-based fluids, will no longer meet the industry’s needs as operational environments evolve. A new stimulation fluid developed by AkzoNobel, Dissolvine StimWell, is based on glutamic acid diacetic acid (GLDA) and has been successfully applied in the field.
GLDA has high thermal stability and low corrosion potential, and is an effective stimulation fluid without adverse environmental impact. A vertical gas well in a deep, sour carbonate reservoir was successfully stimulated using GLDA. Previous matrix stimulation treatments with conventional acids in this HT gas well did not sustain the performance, and a fracture treatment was considered for the well. However, the case proved that matrix acidizing with the GLDA-based fluid was the best stimulation method for the well in terms of cost-effectiveness and regulatory issues.
Stimulation Purpose
The object of stimulation is to remove the production zone damage caused by the drilling and completion processes in sandstone reservoirs, and to create channels or wormholes in carbonate reservoirs. Although an industry workhorse for decades, hydrochloric acid (HCl) often produces subpar stimulation results, especially at high temperatures, because of its fast reaction near the wellbore, low acid penetration, and high corrosivity. Many problems may occur during sandstone acidizing with HCl/hydrofluoric mud acid, such as decomposition of clays in HCl acids, precipitation caused by the presence of fluoride, silica gel filming, and colloidal silica gel precipitation. As a result, mud acid may cause significant damage to sandstone reservoirs, especially for those with a high content of calcite or clays such as illite. The desirable alternative stimulation fluid would be suitable for all of these conditions, be globally applicable, and have an acceptable environmental profile.
Fluids based on GLDA meet those requirements. The fluids are effective in improving permeability in carbonate and sandstone formations. Many additives such as iron control agents that are required in other fluids are not needed in GLDA-based stimulation fluids.
Techbits: Defining Unconventional Resources
Authors: JPT staff _ 
Published: February 2015

Techbits
SPE recently held an Applied Technology Workshop (ATW) on “SPE Petroleum Resources Management Systems (PRMS) Reserves and Resources Definitions–Applicable to Both Unconventional and Conventional Resources?” in Penang, Malaysia. The unprecedented growth in the exploration and production of unconventional resources in North America has sparked widespread interest in the Asia Pacific region. In parallel with the North American shale gas boom, the emergence of several mega coal seam gas to liquefied natural gas projects in Australia has also renewed interest in coalbed methane (CBM) in the region.
The differences in reservoir characteristics and producing mechanisms between conventional and unconventional resources have provided technical, developmental, and economic challenges to the industry, with consequential effects on resource assessment. The question therefore arises as to the suitability and applicability of the SPE PRMS to unconventional resources.
The workshop attracted 93 participants, representing 13 countries and 23 organizations. The program committee for the workshop consisted of 12 members:
Cochairperson:
Norhayati Hashim, Petronas
David Ahye, Gaffney, Cline and
Committee member:
Yousef Al-Shobaili, Saudi Aramco
Abdolrahim Ataei, Petronas
Kamarul Ariffin Buang, ExxonMobil E&P Malaysia
Bruce Gunn, RISC
Greg Horton, Santos
Krit Ngamkamollert, PTT Exploration and Production
Douglas Peacock, Gaffney, Cline and Associates
Aidil Shabudin, Petronas
Mike Reeder, RPS
Yang Hua, RIPED, China
Session 1: Introduction/ Opening/Keynote Address
Hazli Sham Kassim, general manager of resources enhancement at the petroleum management unit of Petronas was the keynote speaker. He spoke about the background of the PRMS and its goal to provide a standardized and consistent approach to assessment of risk and uncertainties related to petroleum reserves and resources. He also recommended that the SPE considers introducing abbreviations for Prospective Resource categories, similar to 1C, 2C, and 3C, and 1P, 2P, and 3P and suggested the abbreviations 1U, 2U, and 3U, as currently used internally by Petronas.
Greg Horton, member of the SPE Oil and Gas Reserves Committee (OGRC), then gave an overview of the PRMS and the updated application guidelines document (published November 2011). He also presented an update on what other international professional societies were doing with regard to updating their own guidelines and alignment with the PRMS.
Session 2: Characteristics of Unconventional Reservoirs
Session 2 provided an introduction and overview of the major types of unconventional reservoirs to ensure a common understanding by all. An overview was provided on CBM, tight gas, and shale gas. The session also included an introduction to the application of the PRMS to unconventional reservoirs.
Making Unconventional Resources Less So
Authors: Rassenfoss Stephen 
Published: February 2015

Emerging Technology
The label unconventional resources, for shale or other nontraditional oil and gas formations, has its detractors.
Bruce Vincent, president of Swift Energy, said in a speech in August that “it is not unconventional any more.” The problem, he explained, was that “unconventional sounds unreliable,” despite the large and growing volumes produced by companies like Swift, an independent whose operations include the Eagle Ford Shale.
But those on the technology-development side of the industry describe unconventional development as a precocious newcomer that has achieved much, with the US predicted to be the world’s largest producer by the end of the decade, but it is far from mature.
When SPE’s six technical directors were asked to talk about some of their priorities for technology development in unconventional reservoirs, they pointed to the areas where change is needed to realize the potential for resources. On the list are improved reserve estimates, adding flexibility to standardized drilling and completion methods, and a greater focus on what it will take to maximize long-term production.
A word used over and over by Vincent and the tech directors was optimizing.
The business whose methods have evolved based on experience will have the opportunity to improve its results based on increasing data from testing.
“We will know so much more in a year to two years from now,” said Shauna Noonan, SPE technical director for Production and Operations. “We are in uncharted territory. We are learning something new every day.”
The growing body of information will raise more questions, and make demands on operations. The “cookie cutter” methods developed to economically deliver the thousands of wells needed for development in shale and coal-seam methane deposits need to be adjusted to allow changes and tradeoffs between spending and performance.
Adjusting where a formation is fractured is likely to add cost, but could pay off in greater production if the system allows well-to-well adjustments.
There is also a push and pull between the long term and the short term.
The standard systems used to drill wells in an assembly line fashion need to build wells in a way that allows later efforts to extend the life of the field. A small cost saving now may cost more in the future.
Long-term decisions are based on only short-term data from recently developed fields. There is a need for statistics-driven methods to mine the data in search of ways of predicting what will happen over the long term and what changes are likely to enhance that outlook.
Future production declines are predicted based on old models developed for conventional reservoirs, which perform quite differently. More resources need to be committed to developing better methods to measure the productive reservoir volume—the area where natural and manmade fractures allow oil and gas to flow—and the amount it will ultimately yield.
Natural Gas: A Rich Resource for Technological Challenges
Authors: Rassenfoss Stephen 
Published: February 2015

Emerging Technology
When Gerald Schotman Shell’s chief technology officer looks at the unconventional oil and gas business, he sees so many young technologies and “from the perspective a chief technology officer, that is such an opportunity.”
Shell’s list of promising areas for research and development is broad, ranging from creating cheaper, more effective sensors for seismic testing to a new generation of specialized, automated drilling rigs.
The goal is always “change that creates value.” In natural gas the rewards can be broken down three ways: produce more gas per well now, bring down the costs per well, and reduce the footprint when doing so.
The footprint can be defined in many ways: the size of the pads used for drilling multiple wells; the level of emissions; the water used; and the many ways exploration and production can touch the people and the environment, near and far.
The long list of things to do represents large investments of money and time, which Schotman says could be rewarding in multiple ways.
“As it happens, some of the research helps two or three goals at a time,” Schotman said in an interview. Often with “the gas agenda a nice thing is you do not have to trade off.”
A continuously better understanding of why specific fractures are more effective than others could lead to hydraulic fracturing methods using less water and sand, saving money, producing more, and reducing the footprint.
There is a wide range of research to respond to “the things where we can find new approaches for these plays.”
Enhanced seismic imaging is a priority because many of the growth areas are in tight, poorly understood rocks onshore, such as shale and coal-beds. Laboratory studies are needed to observe how reservoir rocks interact with hydrocarbon molecules on a microscopic scale.
The goal is to learn: “How is Mother Earth organized to release these molecules, and what is the most low-energy way to get it into the wells?” he said.
Rethinking Exploration
Unconventional formations demand unconventional approaches.
“You have to get back to the fundamentals to make it a business,” Schotman said. “With these types of plays there are specific cost challenges….There are things that do not work well for these plays.”
The reasons are many and the rocks are complex, but generally unconventional formations require more inputs for less output than conventional formations.
Artificial Intelligence Comes of Age in Oil and Gas
Authors: Braswell Gentry 
Published: February 2015

Artificial Intelligence
Once the stuff of science fiction, artificial intelligence (AI) has become ubiquitous in our daily life, and the modern oil and gas industry is no exception.
Artificial neural networks, fuzzy logic, and evolutionary algorithms are common among AI techniques being applied today in oil and gas reservoir simulation, production and drilling optimization, drilling automation and process control, and data mining.
“Today, when you talk to information technology (IT) people, they mention four trends: social media, mobile devices, the cloud, and big data,” said Reid Smith, manager of IT Upstream Services at Marathon Oil, and a fellow of the Association for the Advancement of Artificial Intelligence.
Social media are in everyday use for collaboration; mobile devices are proving valuable in field operations; cloud computing has the potential to deliver cost savings and increased flexibility and performance in networking and data management; and hyperdimensional, complex, big data are well suited for analysis by machine learning, which is a key element of today’s applications of AI.
In addition to a large existing volume of historical oil and gas data, today’s increasingly complex upstream environments generate vast amounts of data for which the value is greatly enhanced with cutting-edge IT. “Some argue there is a substantial amount of oil to be found by applying new analysis techniques to data already on the shelf,” Smith said.
It is important to distinguish between data management and AI. SPE’s Artificial Intelligence and Predictive Analytics (AIPA) group was previously a subsection of SPE’s Digital Energy Technical Section. Now it constitutes its own technical section, Petroleum Data Driven Analytics. Essentially, digital energy is the curating—gathering, storage, and generation—of data, whereas AIPA involves using the data to perform tasks without human intervention, said Shahab D. Mohaghegh, professor of petroleum and natural gas engineering at West Virginia University, and founder of oil-field consulting and software company Intelligent Solutions, Inc. (ISI).
“There is a push in our industry toward smart fields,” Mohaghegh said. “There is a misconception in our industry today that equates automation with intelligence. Just because an operation is automated does not mean that it is smart. Without AI, you may have auto-mated fields, but you will not have smart fields. An automated field may provide the brain, but AI provides the mind. AI is the language of intelligence; it is what makes the hardware smart. To fully realize this, one must subscribe to a complete paradigm shift.”
A good modern example of the data-driven model outside the industry is credit card fraud detection and prevention tools that monitor consumer purchasing habits. “At ISI, that’s how we build reservoir management tools today,” Mohaghegh said. “We are now using the pattern recognition power of this technology to predict, manage, and design hydraulic fracture details in shale, using the hard data rather than soft data.”
Surveillance and Complex Well Work Combine To Extend Life of Mature Field
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 146157, ’Unlocking the Future for a Mature Field: Surveillance and Complex Well Work Combine To Extend Field Life,’ by Matthew Dunning, SPE, John Stripe, Patrick Keatinge, Peter Newton, Ann Davies, SPE, and George Waugh, BP Exploration, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.
Ravenspurn North is a mature gas field forming part of BP’s United Kingdom Continental Shelf portfolio. The field commenced production in 1990 through 42 wells and three platforms; but, by 2006, half of the wells had ceased to flow. A surveillance campaign suggested a common failure mode for many wells, a postulation that large amounts of proppant had accumulated in the wellbore. Pressures measured downhole above the proppant fill supported a significant increase of the remaining gas potential. A project to rejuvenate this field was initiated in 2007.
Introduction
Ravenspurn North encompassed two discrete areas—a relatively high- permeability area referred to as the “sweet spot” where wells were completed without any stimulation and a low-permeability area referred to as the “tight spot” where every well was hydraulically fractured with up to 1.3 million lbm of ceramic proppant. The hydraulically fractured wells were generally located on unmanned satellite towers.
By 2006, 50% of the wells across the field had ceased flowing, the majority of these being the fractured wells in the tight spot. With production falling, Ravenspurn North was facing an uncertain future.
Building the Technical Case
In 2007, a thorough review of BP’s southern North Sea fields was completed with the objective of bringing fresh perspective to these mature fields. For Raven spurn North, the opportunity to repair and reinstate wells to production appeared logical. However, available surveillance data suggested limited remaining-resource potential, and it was believed that the wells that had ceased to flow had simply produced most of their contacted gas. If this was correct, then undertaking expensive interventions to repair the wells would not be wise. The story, though, was far from crystal clear.
First, the remaining-resource estimate was based on P/z trends that were recognized to contain uncertainty in a tight gas environment because the wells never truly reached steady-state production. In early time, the P/z trends presented a credible straight-line fit; however, in later time, a number of higher-pressure measurements that did not fit the trend were observed (Fig. 1). Because the majority of the data points were surface pressures converted to bottomhole pressure, some of the measurements could be explained partly by hydrostatic uncertainty. Other data points, though, were believed reliable and indicated higher reservoir pressures than the overall trend would suggest, pointing to higher contacted gas and the possibility of more potential in these wells.