bluuebunny/crossref_metadata_2025_split huggingface dataset:
IOCs, NOCs Discuss Common Challenges, Developing Local Content
Authors: Henni Abdelghani 
Published: February 2015

Summit review
How resource-rich countries can build sustainable economies through partner-ships with the oil and gas industry was the focus of a recent industry/government summit in Dubai. Key executives from national oil companies (NOCs), private firms, and governments met for 2 days at the National Oil Companies and Governments Summit held in Dubai in late September. Among the companies participating were Saudi Aramco, Kuwait Oil Company, Shell, Total, and ExxonMobil.
Opening the conference, the head of the International Energy Forum (IEF) advocated increased transparency of oil data from the region’s oil producers in the interest of stabilizing oil prices. “If you want markets to be stable, you should be working toward market transparency,” said Aldo Flores-Quiroga, secretary general of the IEF, an 89-member country organization that promotes global energy dialogue. He pointed to the differing oil demand forecasts of OPEC, the producers’ cartel, and the International Energy Agency, the group that represents oil consumers in advanced economies.
He noted that in the forecasts to 2035, there is a discrepancy of 30 million BOPD between the two. “Discrepancies like this matter,” said Flores-Quiroga. “What you estimate about demand will influence what you do about supply.”
IOCs Defend Themselves
In a panel session on developing resources and stimulating long-term sustainable growth, speakers from major international oil companies (IOCs) shared their experiences and strategies in developing local content and helping governments and NOCs achieve their objectives.
Mark Carne, executive vice president for Middle East and North Africa (MENA) at Shell Upstream International, said that the purpose of the summit was to discuss strategies to drive job creation and skills development, and to enhance country value. Instead of working toward achieving this goal, the oil and gas industry has adopted strategies against the development of a local labor force. “Adopting industry ‘best practices’ such as low-cost country sourcing and global framework agreements has meant, in some cases, that job creation opportunities have moved to other countries,” he said.
Research and Development at Universities: Worldwide Change in Petroleum Engineering
Authors: Braswell Gentry 
Published: February 2015

The fundamental properties of hydrocarbons and the basics of drilling will always remain the same. Nevertheless, innovation in petroleum engineering by researchers at universities around the world is changing the face of oil and gas drilling and production in the 21st century. In addition to traditional approaches, technologies for enhanced production from mature fields; production methods for unconventional resources such as tight gas, methane hydrate, and heavy oil; and experimental nanotechnology applications today are critical and increasingly are a part of petroleum engineering research and technology development.
Schulich School of Engineering, University of Calgary, Canada
The upstream research at Schulich’s Department of Chemical and Petroleum Engineering concentrates on improving the exploitation of Canadian unconventional oil and gas resources such as heavy oil and bitumen, and tight gas formations. The department has a dozen research teams, said professor Brij Maini.
The In Situ Combustion Research Group specializes in laboratory and numerical simulation studies of the in-situ combustion of heavy oils, and high-pressure air injection in light oil reservoirs.
The faculty’s EnCana/Paleontological Society of Canadian Institute of Mining, Metallurgy, and Petroleum Endowed Chair heads the department’s joint industry project studying the geomechanics of shale gas. The CMG Foundation Chair in Reservoir Simulation is developing fast and reliable reservoir simulators for the recovery of oil, gas, and coal. The NSERC Industrial Research Chair in Heavy Oil Properties and Processing is researching the properties and phase behavior of heavy oil and solvents. Schulich’s SHARP (Solvent/Heat Assisted Recovery Processes) consortium is supported by 11 local and international companies.
The improved heavy oil science and technology group is studying various aspects of heavy oil recovery technology, including cold heavy oil production with sand, and solvent-based recovery processes and steam additives for steam injection-based processes.
Finding New Talent in a Talent Gap
Authors: Coton Simon 
Published: February 2015

Talent & Technology
It is a truism that most long-dreaded events fail to materialize as catastrophically as predicted. For the global oil industry, the well-anticipated “great crew change” or the “talent gap” is not one of those false alarms.
By whatever name, the talent and skill shortage is here. And every sign by our measure is that the anticipated problems are both real and understated. Oil and gas companies today are more challenged than before to develop innovative strategies to find and train new talent. New solutions, such as poaching from other industries and canvassing for job seekers among returning veterans, have become increasingly successful.
The Problem Areas
Our firm has noted several challenging areas. They are:
A number of approved projects that were put on the back burner during the global recession have started to come back on line. Since they were approved years ago, the companies will want to hit the ground running, rather than spending time ramping up. Such projects will find the talent/skill shortage as bad as predicted.
Several of the hottest spots for exploration and production activity, such as Brazil and Iraq, are in need of new talent and expertise to meet their goals. Just rebuilding Iraq’s dated infrastructure, for instance, could take a giant share of the world’s graduating chemical, mechanical, electrical, and civil engineers for years.
The same could be said about Brazil, which has embarked on one of the largest development plans in its history. But its ambitious and well-funded goals show an estimated talent shortfall of 40,000 engineers for the foreseeable future. In these two hot spots and others, the shortage will be as bad or worse than predicted.
Many of the newer skill areas across the industry, whether in oil sands, tight gas, shale gas, shale oil, or ultradeep sea operations, need tomorrow’s experts and today’s expertise. But the talent is simply not available today. These new projects will also find the talent shortage a challenge.
Field Trials of Reservoir Nanoparticles Reveal Stability, High Rates of Recovery
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 142592, ’Industry First Field Trial of Reservoir Nanoagents,’ by Mazen Y. Kanj, SPE, Saudi Aramco, and M. Harunar Rashid and Emmanuel P. Giannelis, Cornell University, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25-28 September. The paper has not been peer reviewed.
The promise of nanotechnology becomes limitless with the possibility of having functionalized molecular agents to illuminate the reservoir and intervene to alter adverse oil recovery conditions. The future reality of the reservoir nanoagents concept was laboratory and field demonstrated with the industry’s first building block nanoagents’ template. The industry’s first proven reservoir nanoagent template is introduced and demonstrated by means of a push/pull field trial in an observation well.
Introduction
A milestone achievement on the road to having in-situ reservoir nanoagents features an industry-first building block template named Arab-D Dots (A-Dots). The synthesis is proved to be very amenable for scaling up in support of a field operation.
Reservoir Rocks
The Jurassic Arab-D is the most prolific oil-bearing formation of the Ghawar field in Saudi Arabia. Ghawar (Fig. 1) is the largest discovered oil field in the world today. From its northern extremity, the field extends southward some 150 miles as essentially one long continuous anticline, approximately 25 miles across at its widest point. The Arab-D formation constitutes one of the main reservoirs of Saudi Arabia and is composed of reservoir-quality limestone and dolomite. The Arab-D reservoir has an average thickness of more than 200 ft. On the finer scale, it can be further subdivided into four major shoaling-upward carbonate cycles (Fig. 1).
The A-Dot Particles
A-Dots are carbon-based fluorescent nanoparticles. Carbon nanoparticles represent a unique class of nanomaterials that are generally synthesized through a hydrothermal treatment process. Analogous to their well-known cousins, fullerenes and carbon nanotubes, carbon nanoparticles exhibit interesting optical (and electrical) properties that may be exploited in oil and gas applications. A-Dots are developed with a functional stability to survive a lengthy transit in a harsh environment in an oil reservoir, which can be read and interrogated reliably when the nanoparticles are recovered. This translates into required stability at temperatures exceeding 100°C and salinities exceeding 120,000 ppm in total dis-solved solids in the presence of divalent (as well as monovalent) ions such as Ca++, Mg++, and SO4−−.
Preliminary Test Results of Nano-Based Fluids Reveal Benefits for Field Application
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 139534, ’Preliminary Test Results of Nano-Based Drilling Fluids for Oil- and Gasfield Application,’ by M. Amanullah, SPE, Mohammad K. Al-Arfaj, and Ziad Al-Abdullatif, Saudi Aramco, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed.
The oil and gas industry is looking for small, chemically and thermally stable, biologically degradable, environmentally benign material to use in the design of smart fluids. Because of highly enhanced physiochemical, electrical, thermal, and hydrodynamic properties, nanomaterials are considered a promising material. Recently developed nano-based fluids were formulated to study the rheological and filtration properties and evaluate fluid suitability for oil- and gasfield application. Initial test results indicate that the newly developed nano-based drilling mud produces suitable high- and low-end rheological properties.
Introduction
Water- or oil-based drilling fluid is the first foreign fluid that contacts the reservoir zone of a borehole. Most muds contain particles that are part of the mud formulation. These desirable mud solids can cause severe formation damage in the presence of a poor quality mudcake. Moreover, the cutting debris generated while drilling may produce enough microsized and colloidal particles to cause severe formation damage if a poor quality mudcake is deposited on the borehole wall. Hence, drilling muds that are unable to form a well-dispersed, tight, thin, plaster-like external mudcake on the borehole wall can cause serious formation damage because of the formation of an internal mudcake.
Spurt loss associated with most of the mud systems is one of the notorious sources of solid-particle and particulate invasion in the vicinity of the wellbore. Fine particles coming into the drilling mud as a part of drill solids may also cause severe formation damage if the mudcake formed on the borehole wall is poorly dispersed, is very thick because of particle flocculation, and has highly porous fabric because of loose-fabric formation by the flocs, aggregates, and particles.
The thickness of the deposited mudcake is also a critical factor in many drilling and reservoir-engineering problems. Muds producing soft and thick cakes increase the potential of differential sticking and, thus, are not desirable for geological formations highly prone to differential sticking.
Integrated Completion Design for Horizontal Wells in Unconventional Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147120, ’An Integrated Approach To Design Completions for Horizontal Wells in Unconventional Reservoirs,’ by R. Jain, SPE, S. Syal, SPE, T. Long, SPE, and C. Wattenbarger, SPE, ExxonMobil, and I. Kosik, SPE, Imperial Oil Resources, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
An integrated workflow was tested for designing completions for a heavy-oil-recovery process that involves injection and production through the same wellbore. To capture the effect of variations or uncertainties in reservoir and fluid-flow characteristics over time, the transient effects are particularly important while analyzing the long-term performance for these types of completions. The proposed integrated workflow involves initial screening and selection of flow-restricting completions that can meet the desired injection and production performance on the basis of a detailed wellbore-hydraulics-modeling tool.
Introduction
Producing heavy oil and bitumen involves technologies such as cold mining for shallower resources or in-situ viscosity reduction. The cyclic solvent-based process involves alternating cycles of injecting a viscosity-reducing solvent into the reservoir followed by production of a mixture of heavy oil and solvent, with reduced viscosity, through the same wellbore.
Many cyclic-process implementations are intended for use in horizontal wells. The completion design for such a process involves ensuring good solvent distribution into the reservoir during the injection phase to mobilize the resource along the entire wellbore and maximize the well length to reduce field-development cost. The process of injecting and producing from the same wellbore entails additional constraints on the completion design. One constraint is controlled injection distribution by use of flow-restriction devices such as orifices while maintaining a minimal pressure drop across the completion during the production phase.
Another challenge results from the adverse mobility ratio of the solvent mixture and bitumen during the injection process, which could result in viscous fingering. This fingering can cause wide variations in the solvent injection and may cause an undesirable pressure distribution within the reservoir, which, in turn, may affect solvent placement. Predicting such differential injection or a thief zone is difficult because of the inherent nature of instabilities associated with the fingering process.
Long-Term Gas-Hydrate-Production Test, North Slope, Alaska
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22152, ’Evaluation of the Hydrate Deposit at the PBU-L106 Site, North Slope, Alaska, for a Long-Term Test of Gas Production,’ by George J. Moridis, SPE, and Matthew T. Reagan, SPE, Lawrence Berkeley National Laboratory; Heidi Anderson-Kuzma, SPE, East Donner Research; Yang Zhao, University of California at Berkeley; Katie Boyle, Lawrence Berkeley National Laboratory; and James W. Rector, University of California at Berkeley, prepared for the 2011 Arctic Technology Conference, Houston, 7-9 February. The paper has not been peer reviewed.
To investigate the technical feasibility of gas production from hydrate deposits, a long-term field test (lasting 18 to 24 months) is under consideration in a project led by the US Department of Energy. A candidate deposit involving the C-Unit in the vicinity of the PBU-L106 site on the North Slope, Alaska, was evaluated. The results indicate that production from horizontal wells may be orders of magnitude larger than that from vertical wells.
Introduction
Gas hydrates (GHs) are solid crystalline compounds of water and gaseous sub-stances that are described by the general chemical formula GsNH H2O. In the GH clathrates, the molecules of gas, G (referred to as guests), occupy voids within the lattices of ice-like crystal structures. If gas and H2O availability is not a limitation, hydrate deposits can occur in two distinctly different geographic settings in which the necessary conditions of low temperature, T, and high pressure, P, exist for their formation and stability: in the Arctic (typically in association with permafrost) and in deep ocean sediments. CH4 is the dominant GH-forming hydrocarbon gas in natural hydrates that occur in geologic media. Under standard T and P (STP) conditions, each cubic meter of simple CH4 hydrate releases, upon dissociation, approximately 164 m3 of methane and 0.8 m3 of H2O.
Classification. Natural GH accumulations are divided into three main classes on the basis of simple geologic features and initial reservoir conditions. Class-1 settings have two layers: a hydrate- bearing layer (HBL) and an underlying two-phase-fluid zone containing mobile gas and liquid water. A distinct feature of Class-1 settings is that the base of the GH-stability zone coincides with the bottom of the HBL. Class 1 is the most desirable target because it is the easiest to destabilize to release gas. In Class-2 settings, an HBL overlies a zone of mobile water. Class-3 accumulations have a single HBL with no underlying zone of mobile fluids.
Investigating Liquid Loading in Tight Horizontal Gas Wells
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, ’Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator,’ by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.
Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories.
Introduction
Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa.
The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×103 m3/d to 14×103 m3/d after 12 months and to 10×103 m3/d after 36 months.
Improved Riser Management Situation Awareness Through 3D Visualization
Authors: Jensen Gullik A. 
Published: February 2015

Young Technology Showcase
As with many monitoring and decision support tools, riser management systems originate from the engineering community so may assume a large degree of domain knowledge. Unfortunately, this knowledge is not always found among offshore personnel, which prevents the full potential of the monitoring tool to be realized. This may have a negative impact on riser operations and, in turn, on drilling safety and efficiency.
The Kongsberg Riser Management System (RMS) is a real-time monitoring and decision support system for safe and optimum operation of drilling and workover riser systems. Recognizing the potential gap between what the system can do to enhance these operations and what the operator can actually make it do motivated the development of a new user interface for the RMS operator station. It differs from traditional RMS interfaces as it has been developed based on a virtual model of the riser and its environment in three dimensions. The model is built from the data available in the system for riser and vessel representation and is updated in real time to reflect the changing state of the riser based on real-time sensor measurements and advanced computations.
Through the new user interface, the operator can navigate in a virtual space to inspect different aspects of the current operational situation, either by taking a step back for overview, or by zooming in to examine the details. The advantage of this technology is the improved operator perception of the actual situation that contributes to enhanced situation awareness. Likewise, through real-time 3D visualization, the operator can take full advantage and maximize the results gained from all RMS system features.
In operation, the updated user interface presents the monitoring and advisory features of the system in a context that the operator can easily relate to. This makes the system better suited to contribute to a safer and more optimal operation of the riser system during the drilling operation.