bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low-Frequency Water Hammer for Extended-Reach Applications
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163883, ’Investigation of Low-Frequency Water Hammer for Extended- Reach Applications,’ by R. Macdonald, SPE, B. Jennings, and G. Vecseri, TeleDrill, prepared for the 2013 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 26-27 March. The paper has not been peer reviewed.
Horizontal wellbores typically encounter inefficiencies caused by friction during drilling and completion operations. In severe cases, advancing the bit or downhole tools farther into the hole is almost impossible because of the inability of existing technology and methods to overcome downhole-friction forces. This problem is experienced in drilling, completion, and intervention activities and is particularly acute in coiled-tubing (CT) -deployed bottomhole assemblies. It is proposed that a downhole pressure-oscillation tool be developed that enables managing downhole pressure-oscillation amplitude, independent of flow rate. It also is proposed that such a tool, operating at low frequencies, could simultaneously encode downhole measurements within the pressure-pulse signal.
Introduction
Significant innovation has been applied to the challenge of improving weight transfer and delaying the onset of helical buckling when using CT in the horizontal section of wellbores. Numerous technical approaches have been tried with varying degrees of success and economic benefit. Examples include lubricants; tractors; friction-reduction tools; and larger-diameter, tapered, or hybrid work strings.
Recently, the industry has shown interest in the performance of downhole friction-reduction tools in CT drillout operations. The general operating principle of this class of tools is to create a pressure oscillation at a particular frequency that induces motion in the CT. This motion reduces the friction force, improving weight transfer and extending the reach. The greater the pressure oscillation, the greater the induced motion and friction-force reduction.
The mechanical nature of commercially available downhole friction-reduction tools requires that they be adjusted at the surface to generate a pre-determined pressure-oscillation amplitude, in a defined frequency band, at a given flow rate. Flow rate and pressure amplitude correlate positively, which leads to an increase in backpressure as the flow rate increases and, conversely, a reduced backpressure and friction-force-reduction capability when flow rate decreases.
Technology Focus: Wellbore Tubulars (June 2013)
Authors: McDonough Casey 
Published: February 2015

Technology Focus
When the first pipelines moved crude from wellhead to market in the early 1870s, it was difficult to balance the product in the line to the storage tanks at each end. If the receiving station was not ready for the crude, the sending station risked pumping too much product and might have overfilled the receiving station’s tanks. Communications were by telegraph in those days, but telegraph lines were usually run along railroads, not pipelines. Instead of telegraphing what was coming down the pipe so that the receiving station could get ready for the volume, the sending station would open and close a valve and pressures and volumes would be received at the other end. Morse code by pressure waves was used instead of the electrical current and electromagnetism of the Cooke and Wheatstone telegraph. This pulsing is thought to be the beginning of the measurement-while-drilling mud-pulse technology of today.
Several technological efficiencies have been achieved to increase the data rate of the mud-pulse technology, but they increased the data rate only marginally. Restricting the flow of mud inside the drillpipe through a poppet-and-orifice combination or modulating it through a siren would give longs and shorts like the dashes and dots of Morse code. Negative pulse technology added a small increase in efficiency. It used sharp pressure drops out the drillstring that provided a sharper signature at surface that was tied to time events and a few more bits could be compacted together. Electromagnetic systems send information to the surface with low-frequency electro-magnetic waves. The technology uses the flow of electricity to transmit bits. It has its applications but is dependent on the formation resistivity and depth. Wired drillpipe is a step-change solution for higher downhole data rates. If the cost can become competitive and the product is robust enough, data rates required to send high-definition images will be realized and the choice will exist to increase the data rate to 1 million times that of electromagnetic or mud-pulse telemetry.
Tubulars are evolving to become data transmitters of increasingly larger band-width. In both the drilling and completion phases, greater bandwidth is required to monitor the stimulation of a well and to drill a wellbore more efficiently. Evaluating position in the lateral while drilling, monitoring drilling efficiencies downhole, and monitoring stimulation efficiencies all require greater bandwidth. Conventional wire and even fiber-optic cable are being used in innovative ways, in harsh conditions, to solve these evaluation issues.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE/IADC 163420 Drillstring-Mechanics Model for Surveillance, Root-Cause Analysis, and Mitigation of Torsional and Axial Vibrations by Deniz Ertas, ExxonMobil, et al.
SPE/IADC 163449 RFID—A Key Enabler in Drilling Automation by Mads Grinrod, Minerals Group, et al.
SPE 157388 New Test for Material Resistance Against Microbiologically Influenced Corrosion by Jeppe Jensen, DTI Oil & Gas, et al.
Wired-Drillpipe Field Trials Reveal Potential Benefits Over Traditional Pipe
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163560, ’A Summary of Wired-Drillpipe Field Trials and Deployments in BP,’ by Stephen T. Edwards, Chris J. Coley, Nick A. Whitley, Richard G. Keck, SPE, Vishwahnath Ramnath, Tommy Foster, Keith Coghill, and Mark Honey, SPE, BP, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
Field trials were conducted by BP on the commercial version of wired pipe with a comprehensive suite of logging-while-drilling (LWD) tools, measurement-while-drilling (MWD) functionality, and rotary-steerable- capability on two Wyoming wells in 2007. Since then, BP has deployed wired pipe commercially in more than 14 wells at four additional locations (Trinidad, North Sea, Colombia, and deepwater Gulf of Mexico), representing a good cross section of drilling conditions and challenges.
Basics of How Wired Pipe Works
Wired drillpipe incorporates a section of coaxial cable in each joint. The cable passes through a gun-drilled hole in the connection on each end of the joint. Between connections, the cable is encased in a strong stainless-steel sheath, which is held in tension within the inner diameter of the pipe adjacent to, but not bonded to, the inner wall. Figs. 1 and 2 show schematics of the wired pipe.
Inductive coupling enables the signal to pass from one joint to the next, through ferrous coils that are embedded in the pin end of one joint of pipe and the opposing box end of the subsequent joint of pipe. These coils come very close to each other when the connection is made up, but, because the coupling is inductive, they do not need to touch, and insulating material such as pipe dope does not block the signal. However, over many joints of pipe, there is a loss of signal strength, and, for this reason, a battery-powered booster sub is deployed approximately every 1,500 ft. The booster assemblies also provide housing and a connection point for along-string measurements. On the bottomhole-assembly (BHA) end of the drillstring, wired pipe connects to the measurements providers and steering assembly through an interface sub, enabling two-way communication to the network, usually provided by the LWD provider. At the top of the drillstring, the network is connected to surface servers by a data swivel housed in the top drive.
Wired-Pipe-Enabled Applications
Real-Time Imaging. Several different LWD imaging tools are commercially available today. Two types of tools that have been run with wired pipe are the LWD azimuthal density imaging tool and LWD resistivity imaging.
Case Study Examines Safely Exceeding Buckling Loads in Long Horizontal Wells
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163518, ’Safely Exceeding Buckling Loads in Long Horizontal Wells: Case Study in Shale Plays,’ by S. Menand, SPE, DrillScan, and D. C-K Chen, SPE, Hess, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.
The general industry perception is that, when drillings or casing strings exceed conventional helical-buckling criteria, they cannot be operated safely in the hole because the risk of failure or lockup is too high. However, some theoretical, experimental, and field case studies have shown that a tubular may be run in the hole even in a buckling state within safe limits.
Introduction
Buckling occurs when the compressive load in a tubular exceeds a critical value, beyond which the tubular is no longer stable and deforms into a sinusoidal or helical shape. Sinusoidal buckling corresponds to a tube that snaps into a sinusoidal shape, and it is sometimes called lateral buckling, snaking, or two-dimensional buckling. Helical buckling corresponds to a tube that snaps into a helical (spiral) shape.
Recent studies have shown that the conventional sinusoidal- and helical-buckling criteria are accurate only in a perfect wellbore geometry because wellbore tortuosity and doglegs play a great role in the buckling phenomenon. An example is illustrated in Fig. 1, which shows that sinusoidal and helical buckling take place simultaneously despite the same compression; doglegs and tortuosity play an important role in the onset of buckling.
Compression on the drillpipe is maximal when tripping in, running casing/liner, or performing slide drilling. Buckling may also occur when drilling with a rotary assembly with a large weight on bit (WOB). The critical helical-buckling load for a rotating pipe may be approximately 50% less than that obtained for a non-rotating pipe. The helical-buckling load is generally the load used in drillstring or casing design to define the limit upon which the tubular might be fully buckled, with the risk of getting stuck or with the risk of large bending stresses that may lead to failure. During well planning, if the compression in the drillstring exceeds the critical helical-buckling load, drilling engineers usually modify the drillstring design until this buckling does not occur. It is widely recognized that sinusoidal buckling is not harmful to a tubular, but helical buckling is generally perceived as a dangerous situation.
New Design of Solid-Expandable Tubular Aids Patching of Hard-To-Reach Casing
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16429, ’Innovative Design of the Solid-Expandable Tubular To Patch the Casing: Area Below the Previously Installed Expandable Tubular,’ by Tao Li, Shan Gao, Qiang Chen, Yiliang Li, Weiye Han, Xiuling Bi, and Qiang Sun, PetroChina, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Solid-expandable tubular (SET) is widely used to patch casing and has proved to be cost effective; however, when the damage is directly below an area previously patched, conventional expandable tubular might not be positioned smoothly because of a loss in wellbore size caused by the previously installed tubular. A new design involves putting the expansion tool outside the tubular. As a result, the expansion ratio could be maximized and the tubular without launcher could pass through the smaller wellbore.
Innovative Structure Design
SET technology is well known for its classic structure (Fig. 1). The expansion tool is put inside the tubular and pushed upward by hydraulic or mechanical means. Usually, rubber is used to seal the annular space between the casing and the tubular. This structure has great advantages in the field and has been used widely across the world; however, one significant weakness cannot be ignored. While the expansion tool is inside the tubular, it restricts the expansion ratio. Therefore, this structure is not appropriate for handling some difficult issues. The most common issue is that the casing often needs to be patched more than once. Usually, the patch position is directly below the previously installed SET, making it almost impossible for the conventional patching tool to be delivered in position. The new design was developed to meet this challenge (Fig. 2).
The expansion tool has been placed outside the tubular, powered by a cylinder and piston. An anchor is used to fix the tubular during expansion (Fig. 3a). As the SET is delivered into position, liquid is pumped into the tubing to activate the piston. Because of the anchor, the expansion tool can expand the tubular, and the expanded part is stuck to the casing, sealing the annular space (Fig. 3b). After the initial expansion, the tubular is fixed to the casing and the anchor is no longer needed (Fig. 3c). The same process then could be repeated until the end of the expansion process (Fig. 3d).
AIME, SPE's Parent Organization
Authors: Fattahi Behrooz , Lawrie-Munro Michele 
Published: February 2015

AIME
Almost everyone in the oil and gas industry is more or less familiar with SPE and its contributions to the industry. But many may not know that SPE has a parent organization: the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME).
AIME was established in 1871 in Wilkes-Barre, Pennsylvania, as the American Institute of Mining Engineers. In 1904, AIME became one of the founding societies along with the American Society of Mechanical Engineers (ASME) and the American Institute of Electrical Engineers (AIEE, later IEEE) to form the United Engineering Society. In 1912, the Iron and Steel Division was created, and in 1918, the American Institute of Metals joined AIME, and the new organization, while still AIME, was called the American Institute of Mining and Metallurgical Engineers.
In 1922, the petroleum division of the AIME was formed. AIME continued to grow until 1956 when AIME officially became the American Institute of Mining, Metallurgical, and Petroleum Engineers. During the 1950s, the petroleum membership of AIME grew rap-idly, warranting the formation of SPE as the petroleum industry’s professional society in 1957 with a membership of approximately 12,500. In 1973, AIME started the process of decentralization and, as a result, SPE became a separately incorporated entity in 1985. Today, AIME is a federation of four not-for-profit professional societies: SPE (with more than 100,000 members); the Association of Iron and Steel Technology (15,000 members); the Society for Mining, Metallurgy, and Exploration (14,000 members); and The Minerals, Metals and Materials Society (12,000 members).
AIME operates under a foundation model, governed by an eight-member Board of Trustees, two appointed by each member society. An executive director manages its operation. The presidency of AIME rotates among its four member societies. Its mission is to support its member societies, through exercising fiscal responsibility, distributing funds, facilitating interaction with the larger scientific and engineering community, enhancing collaboration among the member societies, and honoring the legacy and traditions of AIME. AIME’s vision is to be a relevant and valued partner to its member societies. AIME’s principal activities include funding projects and programs through distributions and grant opportunities, providing forums to share best practices and facilitate collaboration among the engineering and scientific community, and presenting awards and scholarships that honor the AIME legacy and recognize outstanding members and promising students.
Emerging Frontiers: Focus on the Subsea
Authors: Spath Jeff 
Published: February 2015

President's column
Over the past 6 months, I’ve talked about several emerging geographic and technology frontiers in the oil and gas industry. One of the most exciting and prolific emerging technology frontiers is also geographic in a way—the seafloor of deepwater basins around the world. Since the first installation of a subsea production tree in the Gulf of Mexico in 1961, the surge in the deployment of subsea wells has resulted in significant economic and environmental improvements in deepwater development.
High oil prices, technological developments, and the need to counterbalance declining production in mature shallow-water basins have been driving the move of offshore oil and gas operations into deep and ultradeep (&gt;10,000 ft) waters. Growth in this sector has been momentous over the past few decades. Subsea installations will grow from roughly 2,000 in 2001 to an estimated 8,500 by 2018. Growth in capital expenditure (Capex), driven primarily by Asia, Africa, and the North Sea is estimated to grow by 120% between now and 2018.
Increasingly, operators are cost-effectively targeting reservoirs over a much wider area, tying back subsea wells both to fixed platforms in shallow waters and to floating infrastructure in deeper waters. In fact, capital-intensive ultradeepwater developments are expected to capture 48% of Capex and 23% of tree installations in 2014–2017, in contrast to 37% of Capex and 15% of installations in 2008–2013.
Technology Could Cut CO2 Cost Sharply for Enhanced Oil Recovery
Authors: Henni Abdelghani 
Published: February 2015

Technology Update
As oil fields throughout the world are reaching maturity and requiring the use of secondary and tertiary recovery techniques, oil companies are looking for new processes and technologies to extract more oil from these aging fields.
In the next 20 years, an estimated 50% of waterflooded fields will need to shift to enhanced oil recovery (EOR). Carbon dioxide (CO2) has proved to be an almost ideal EOR medium for a broad range of reservoir types and conditions, yielding increases in recovery of up to 15% of oil initially in place.
Most of the experience with commercial CO2 EOR has been gained in onshore oil fields in the United States, particularly in the Permian Basin of Texas, where nearby sources of natural CO2 gas and an extensive CO2 transport infrastructure are available.
“Onshore CO2 flooding is economical at CO2 costs of around USD 35 to 40 per tonne and an oil price of more than USD 75 per barrel,” said Richard Doidge, director of the TriGen CO2 removal technology program at Maersk Oil. “Where natural CO2 sources are not readily available, CO2 may today be sourced from petrochemical and pre- or post-combustion capture plants, for example. However, these capture methods typically yield CO2 prices of USD 80 to 120 per tonne, which would make CO2 flooding uneconomical.”
A ready but limited source of lowcost CO2 can be obtained from facilities, such as ethanol, petrochemical, and gasto- liquids plants, but the bulk of globally emitted industrial CO2 comes from power production and heavy industries, such as steelmaking and cement production.
There are three main approaches to removing or “scrubbing” CO2 from feed or flue gases: precombustion, post-combustion, and combustion. Because of the oxygen required in the combustion mixture, the combustion methods are usually called oxy-fuel processes. The efficiency of these processes depends on, among other factors, the concentration of CO2 in the feed or flue gas and the pressure at which the contaminated gas is treated.
A New Approach to Coiled-Tubing-Integrity Monitoring
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168303, ’Optimizing Pipe Management With a New Approach to Coiled-Tubing-Integrity Monitoring,’ by Michelle Torregrossa, SPE, Liam Zsolt, SPE, and Mirjam Zwanenburg, SPE, Schlumberger, prepared for the 2014 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 25-26 March. The paper has not been peer reviewed.
With the availability of operational magnetic-flux-leakage (MFL) -measurement devices, operators are now able to see many previously undetectable coiled-tubing (CT) defects as they occur and advance. CT operators can now understand the circumstances that caused these defects, the conditions that worsen them, and the methods that can prevent their progress. This work will present an object-oriented tracking system that allows CT operators to monitor defects as they evolve over time.
Introduction
For many years, an integral part of pipe management has been nondestructive-evaluation (NDE) inspections of CT strings. These inspections exist to complement the use of theoretical-fatigue-life (TFL) tracking and mitigation of pipe failures. It is possible to track fatigue, imperfections, and anomalies during the job. These data should be used to optimize pipe management further in field locations. Despite its availability, the practice of conducting real-time NDE by use of MFL principles during job execution has been quite rare. Because NDE tools are becoming increasingly robust and reliable, this technology can now be used at the wellsite during CT jobs and thus data can be analyzed in real time. Sites in Alaska, for instance, run NDE devices in CT-drilling operations, and implement the findings into their pipe-management practices.
Self-Diverting Acid for Effective Carbonate Stimulation Offshore Brazil
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165089, ’Self-Diverting Acid for Effective Carbonate Stimulation Offshore Brazil: A Successful History,’ by A.T. Jardim Neto, C.A.M. Silva, R.S. Torres, R.L. Farias, F.G.M. Prata, and L.A.M. Souza, Baker Hughes, and A.Z.I. Pereira, A. Calderon, and E.F. Sandes, Petrobras, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, the Netherlands, 5-7 June. The paper has not been peer reviewed.
This work describes the positive results experienced when a self-diverting acid system based on a viscoelastic-surfactant (VES) technology was introduced for carbonate-reservoir stimulation offshore Brazil. The self-diverting (SD) VES (SD-VES) promotes viscosity development when the acid comes in contact with the carbonate formation. Since the SD-VES was introduced in this environment in 2009, more than 40 wells have been treated with the system.
Introduction
Matrix acidizing is frequently used to stimulate carbonate reservoirs offshore Brazil. In these treatments, a proper diversion technique is required to direct the treatment fluid to lower-permeability or more-damaged zones and ensure the treatment of the entire production interval. The chemicals developed and used as diverting agents include polymer gels, foams, oil-soluble resins, and rock salt, among others. Offshore Brazil, polymer-based systems have been applied successfully. Such systems are easier to handle than particulates, and diversion is achieved through the formation of natural resistance to viscous flow. Generally, the treatment is divided into three phases: a regular 15-wt% hydrochloric acid (HCl) is pumped first, followed by a gelled 15-wt% HCl, and finally by a pill of insitu- crosslinked gelled 3-wt% HCl. In most cases, several stages are pumped, repeating the three phases in order to cover the entire interval.
Despite the success experienced with polymer systems, concerns about the potential damage to the formation provided an impetus for the successful introduction of a viscoelastic-acid system offshore Brazil.