bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pioneering Subsea Gas Compression Offshore Norway
Authors: Jacobs Trent 
Published: February 2015

The world’s first full-scale subsea gas compression system is in the final stages of construction and is on schedule to be installed in the åsgard gas field offshore Norway by year’s end. Norway’s state-owned oil and gas company, Statoil, says that the project is the largest and most complex subsea development ever undertaken in both size and scope and represents a leap forward for an industry that has sought to produce hydrocarbons ever farther from shore for more than a century. With the ability to process and compress gas far beneath the harsh surface conditions of the Norwegian Sea, Statoil envisions a future where surface installations are not required to develop subsea fields. The concept is referred to as the subsea factory, and the company aims to install one capable of producing both oil and gas by 2020. If successful, the åsgard subsea gas compression project will become the latest milestone in proving that the company’s ambitious objective is possible.
Statoil selected Aker Solutions to design and build the system after determining that a subsea compressor station was economically favorable and had a greater technological potential compared with constructing a semisubmersible platform. By installing a compressor train on the seafloor, “you are closer to the reservoir, which means you can do more with less,” said Svenn Ivar Fure, Aker Solution’s senior vice president of strategy and business development. “You don’t have to take the gas up to a platform and then pump it down again. That provides a lot of advantages,” he said.
Fure also noted that, besides requiring less energy to achieve the same end, a subsea system requires far fewer personnel to maintain and oversee its operation. While subsea facilities do require constant monitoring, it can be done remotely and with far fewer people than necessary for a conventional platform. This provides the operator with considerable saving in regard to salaries, logistical services, helicopter transportation, catering services, and power generation. And, because no personnel work directly on the system day in and day out, the risk for injury and loss of human life is greatly reduced. Additionally, Statoil and Aker Solutions claim subsea compressors involve a simpler build and installation process compared with that of a semisubmersible platform.
ECD-Management Strategy Solves Lost Circulation Issues
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166134, ’Case Study - ECD-Management Strategy Solves Lost-Circulation Issues in Complex Salt Diapirs/Paleocene Reservoir,’ by David Murray, Shell; Mark W. Sanders, SPE, and Kirsty Houston, SPE, M-I Swaco; and Hamish Hogg and Graeme Wylie, Shell, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
Drilling horizontal infill wells in the Pierce field in the UK central North Sea is challenging because of a narrow drilling window caused by depletion in a highly fractured reservoir. Wellbore strengthening was attempted in the reservoir section of Pierce B5 although, when a pre-existing fracture further weakened by depletion was encountered, losses occurred. A detailed analysis of the losses event on Pierce B5 provided an improved understanding of the loss mechanism, resulting in a revised equivalent-circulating-density (ECD) -management strategy.
Introduction
The Pierce field (Fig. 1) in the UK central North Sea is a brownfield development with 17 existing wells drilled around two complex salt diapirs. Oil production was depletion-driven for the first 7 years until pressure support was provided by three water injectors drilled around the southern salt diapir. Pierce B5 was drilled in the proximity of the southern diapir, and losses encountered in the reservoir section were severe enough that no further drilling progress could be made. Preexisting fractures further weakened by depletion were thought to be the cause of the losses. Unfortunately, from a well-planning perspective, these fractures cannot be predicted or avoided when drilling horizontal wells.
During a three-well infill campaign (Wells B5, A11, and C1), considerable losses on the first well led the operator to re-evaluate how future wells would be drilled. The outcome of this was the development of a low-ECD-drilling- fluid system, a revised ECD-management procedure, and a much-improved loss-treatment strategy. This combined strategy was applied in the field and resulted in the successful drilling of the subsequent wells.
Loss Event on Pierce B5
Because of the close proximity in the reservoir of the Pierce B5 well to a preexisting production well (Pierce B2), it was determined that the localized depletion seen at this location because of the drawdown effects of B2 would be on the order of 2,300 psi, which would result in a reduction in formation integrity. However, there was concern that the effects of depletion could be higher than that; 3,200 psi through open fractures was modeled as the worst case. Therefore, because of the potential for dynamic losses when encountering zones that have seen the lowest field depletion and to mitigate the risk of open fractures, the recommendation was made to use a fluid design incorporating wellbore-strengthening materials (WSMs).
Offshore Dry-Docking of FPSOs
Authors: Denney Dennis 
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper OTC 24330, ’Offshore Dry-Docking of FPSOs: A Response to Industry Needs,’ by T. Terpstra and E.A. Hellinga, Dockwise, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
The large number of floating production, storage, and offloading units (FPSOs) commissioned more than a decade ago now require offshore-asset-integrity management and maintenance. The FPSOs were originally designed for continuous service for periods up to 25 years. However, although designed to strict criteria, structural and hull-maintenance shortcomings have become apparent, prompting remedial actions or extensive offshore-maintenance campaigns. An offshore-dry- docking concept was developed to lift an FPSO out of the water without disconnecting it from its mooring system and leaving the flowlines connected. The stable working platform allows work access to the FPSO hull, appendages, and mooring system.
Introduction
The proposed offshore dry-docking concept lifts the FPSO out of the water by submerging the floating dry-dock vessel and moving it underneath the FPSO offshore without disconnecting the FPSO from its mooring system or flowlines, as shown in Fig. 1. The bowless concept of the dry-dock vessel with a high load-carrying capacity enables dry transportation of more-traditional semisubmersibles and other floating production units and FPSOs. The proposed offshore dry dock investigated the use of dry-transportation technology for offshore dry-docking of complete floating production units.
Technical Specifications
The largest heavy-transport vessel currently operating is designed to dry-transport offshore production facilities including ultraheavy semisubmersibles and FPSOs. In the past, an offshore unit would need to be wet towed from the fabricator to its production location. Scaling up the existing heavy-transport vessels was not sufficient because of the length of FPSOs, which can exceed 300 m. A bowless design is capable of transporting and offshore dry-docking FPSOs longer than 300 m, with the strength of the FPSO being the limiting factor. The design is shown in Fig. 2. With its bowless design, the total length of the Dockwise Vanguard (275 m) can be used. Its cruising speed of 12 knots is at least twice the speed of a wet tow. Floating cargoes with a maximum draft of 16 m can be loaded (not considering cribbing or grillage). The dry-dock vessel’s bowless design and the movable casings allow use of the vessel’s entire deck to transport units. Also, there are no vessel restrictions for overhang forward and aft. The bowless design is created by placing the crew’s accommodation on the extreme starboard side of the vessel together with the lifeboats.
Nanotechnology Applications for Challenges in Egypt
Authors: Denney Dennis 
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper SPE 164716, ’Applications of Nanotechnology in the Oil and Gas Industry: Latest Trends Worldwide and Future Challenges in Egypt,’ by Abdelrahman Ibrahim El-Diasty, SPE, and Adel M. Salem Ragab, American University in Cairo and Suez University, prepared for the 2013 North Africa Technical Conference & Exhibition, Cairo, 15-17 April. The paper has not been peer reviewed.
Precise manipulation and control of matter at dimensions of 1–100 nm have transformed many industries including the oil and gas industry. Nanosensors enhance the resolution of subsurface imaging, leading to advanced field-characterization techniques. Nanotechnology could greatly enhance oil recovery by use of molecular modification and by manipulating interfacial characteristics. Egypt’s oil consumption has grown by more than 30% in the past 10 years. Hydrocarbon reserves in Egypt have increased 5%/year over the past 7 years, while the average recovery factor remains at 35%. Nanotechnology is key to solving this production/ consumption imbalance.
Introduction
Nanotechnology is the use of very small pieces of material, with dimensions between approximately 1 and 100 nm, by themselves or by manipulation to create new larger-scale materials with unique phenomena enabling novel applications. A nanometer is one-billionth of a meter— a distance equal to two to twenty atoms laid down next to each other (depending on the type of atom).
Nanotechnology refers to manipulating the structure of matter on a length scale of nanometers, interpreted at different times as meaning anything from 0.1 nm (controlling the arrangement of individual atoms) to 100 nm or more. Fig. 1 compares the scale of various items referenced to a nanometer.
Engineered Nanomaterials
Nanoparticles are the simplest form of structures with sizes in the nanometer range. In principle, any collection of atoms bonded together with a structural radius &lt;100 nm can be considered a nanoparticle. The tiny nature of nanoparticles yields useful characteristics, such as increased surface area to which other materials can bond in ways that make stronger or lighter materials. At the nanoscale, size is a factor regarding how molecules react to and bond with each other.
Suspensions of nanoparticles are possible because the interaction of the particle surface with the solvent is strong enough to overcome differences in density, which usually would result in a material either sinking or floating in a liquid-forming nanofluid. Nanofluids for oil and gas applications are defined as any fluid used in the exploration and exploitation of oil and gas that contains at least one additive with a particle size in the range of 1–100 nm. A few oilfield uses are described in the following. See the complete paper for additional uses and details.
New Choke-Valve Design Improves Separator Efficiency
Authors: Betting Marco , Epsom Hugh 
Published: February 2015

Technology Update
The efficiency of the gas/liquid separation process can have a significant impact on the economics of planned and potential oil and gas developments, as well as on the profitability of existing production operations.
A new type of choke valve that improves the efficiency of downstream gas/liquid separators by enhancing the coalescence of dispersed liquids in a fluid stream has been developed recently by Twister. The initial field test of the technology, known as the SWIRL valve, was performed at a JT-LTS production unit operated by NAM in the Netherlands.
The test demonstrated that the replacement of a conventional JT valve with the coalescing choke valve resulted in a significant improvement in the dewpointing performance of the gas-processing facility. This retrofit also allowed the maximum plant operating flow rate to be increased from 650 000 to 735 000 m3/d, while still meeting export gas specifications. It was additionally found that by using the coalescing valve, the temperature in the cold separator (SMSM type) could be increased by 4–5°C while still meeting specification, allowing a reduction of approximately 3 bars in the plant feed pressure. Furthermore, it was demonstrated during the field test that the glycol losses normally experienced were significantly reduced.
This article presents the initial field-test results and an overview of the subsequent development and deployment of the coalescing-valve technology.
Technology Description
Pressure throttling in a conventional choke valve is achieved by dissipation of the kinetic energy present in the gas flow through randomly distributed eddies. The new coalescing valve, which was developed with the aid of proprietary computational fluid-dynamics models, uses the excess free pressure in a fluid stream to establish a coherent vortex motion. The total pressure inside the vortex core is gradually reduced along the axis of the flow path. By reducing the total pressure in a vortex flow, the flow shear rates are lower, compared with conventional chokes, thereby avoiding excessive breakup of liquid drops. However, and more importantly, these micron-size droplets are concentrated around the perimeter of the flow path, thus enhancing the coalescence to larger, more easily separable droplets.
Techbits: Education Best Practices Discussed in Kazakhstan
Authors: JPT staff _ 
Published: February 2015

Techbits
The SPE Talent Council and the Kazakh National Technical University (KazNTU)—named after prominent Kazakh scientist and academician K.I. Satpayev—sponsored the “Best Practices in Petroleum Engineering Education” workshop in November 2009 in Almaty, Kazakhstan. Adilov Zheksenbeck Makeyevich, rector of KazNTU, was instrumental in bringing this workshop to Almaty, which assembled representatives of academia and industry in discussions related to the quality and quantity of engineering graduates.
The evening before the workshop commenced, a dedication ceremony was held for the SPE/KazNTU Student Chapter Resource Room. Representatives from the SPE Talent Council, industry, university faculty, and students attended the dedication, which highlighted the computer work stations and numerous technical books for use by the student chapter members and contributed by Chevron, Schlumberger, Kappa, and SPE.
Critical Education Objectives Cochairs Mike Sullivan, Tengizchevroil, and Talgat Ablaevitsh, director of the Department of Science at KazNTU, welcomed guests and KazNTU faculty to the workshop, and expressed appreciation to the SPE Talent Council for its support.
Gulnara Sarsenbayeva, director of the Center for International Accreditation at KazNTU, discussed the necessary steps to make KazNTU an internationally recognized university. She stressed that links to the old Soviet educational style must be cut, replaced by new methodologies that are more aligned with a robust international system. Sarsenbayeva discussed the need for stronger links between industry and academia that foster a new sense of cooperation, and advocated that surveys be conducted to assist in the modification and modernization of the university’s curriculum to ensure that it is aligned with market demands.
Ali Ghalambor, professor at the University of Louisiana Lafayette, presented issues regarding accreditation by ABET, a US-based federation of 30 professional and technical societies representing the fields of applied science, computing, engineering, and technology. ABET’s accreditation goals are quality assurance, standardization of evaluation criteria, and uniform criteria benefits to employers and employees (graduates). ABET accreditation places an emphasis on learning rather than teaching, and involves human values that include inquiry-based learning, preparation for lifelong learning, and integrative, systems-based thinking. Basic ABET success criteria to consider include evaluation of student performance, the educational program’s objectives and outcomes, and the quality of the faculty and facilities.
Fluid Selection for Energized Hydraulic Fractures
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124361, ’Fluid Selection for Energized Hydraulic Fractures,’ by Kyle E. Friehauf and Mukul M. Sharma, SPE, University of Texas at Austin, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4-7 October.
Traditional hydraulic-fracture simulators do not take into account the compositional, thermal, and phase-behavior effects that are crucial to the success of energized fractures. Traditional water-based fracturing fluids are not ideally suited for use in tight, depleted, or water-sensitive formations. Gas-energized fracturing fluid addresses the water-trapping problem by creating a high gas saturation in the invaded zone, thereby facilitating gas flowback. A fully compositional fracture simulator was used to evaluate different designs for energized fractures. It showed that energized fluids should be applied to rocks when the drawdown pressure is insufficient to remove the liquid. Use of a compositional fracture simulator allows systematic design of energized-fracture treatments.
Introduction
A hydraulic-fracturing process becomes energized with the addition of a compressible, sometimes soluble, gas component into the treatment fluid. Energizing the fluid creates a high gas saturation in the invaded zone, thereby facilitating gas flowback. It is estimated that one-third of the fractures pumped in the US are energized by a gaseous phase. Energized-fluid fracturing is common in reservoirs that are water sensitive or that have a low pore pressure or low permeability.
In conducting this study, the hydraulic-fracturing model used compositional and energy balances and coupled them with phase behavior, making this model applicable to energized fluids. The productivity-index (PI) -ratio values were calculated with a PI model that takes into account varying fracture conductivity and the damage around the fracture face caused by fluid invasion.
Multiphase-Fracturing-Fluid Properties
As with all fluids, the properties of an energized fracturing fluid depend on fluid composition and the range of conditions under which the fluid is applied. Commonly, CO2 or N2 are added to a traditional water-based fluid to energize the fluid. This paper focused on these fluid systems because they are used most often and because their rheology has been studied to a great extent, but methanol is another possible component. This paper discusses commonly used fluid systems containing the following component mixtures: CO2/H2O, N2/H2O, and CO2/methanol/H2O.
Advanced Production Logging of Horizontal Wells in North Oman
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13309, ’Advanced Production Logging Review of a Number of Horizontal Wells in the North of Oman,’ by T.K. Chang, SPE, Schlumberger, and L. Mieles and P.J. Tarabbia, SPE, Petroleum Development Oman, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December.
The full-length paper reviews the advanced-production-logging jobs performed during 2006–07 in several fields in north Oman. The paper includes the following:
Prejob planning, recommended logging procedures, operational planning and considerations for different types of wells, and well-completion strategy
Factors influencing horizontal production-logging jobs
Evaluation, log quality control, and interpretation of results
Success-rate optimization through candidate selection and best practices
Introduction
Petroleum Development Oman began drilling horizontal wells in the north of Oman in the 1980s. Since then, most development projects have used a high proportion of horizontal and multilateral wells to access reserves. Historically, downhole inflow patterns encountered in these horizontal wells have been challenging to measure and interpret. Recently, a viable production-logging tool (PLT) was identified to increase understanding of real-time three-phase flow to assist in production optimization and proper well and reservoir management. The full-length paper reviews and analyzes a number of logging jobs conducted in the fields of north Oman.
With any well-related operation, it is important to discuss the success rate of obtaining data. Fig. 1 shows the success rate of the PLT in the producing oil fields of north Oman. Successful jobs are indicated by green and unsuccessful jobs by red. “Technical success” (amber) is on the basis of whether the logging objectives set before the job were met. In some cases, well-workover entries were performed on the basis of the findings from the PLT job, and some production gains have been recorded.
The high success rate (13 successful logging jobs out of 18) was partially a result of proper candidate selection, but mostly a result of proper planning. Of the five unsuccessful jobs, two were a result of tool failures and three were either failure to log the entire interval of interest or inability to log because of operational constraints, giving poor-quality data.