bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tandem Downhole-Isolation-Valve System Eliminates Snubbing
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173043, “First Ever North Sea Deployment of Tandem DIV System Eliminates Snubbing—A Case Study,” by Gary Mueller, Weatherford, prepared for the 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed.
The operator of an offshore jackup rig in the North Sea required safe and efficient deployment of the completion string without killing the well during tripping. A solution other than a snubbing unit was needed because of the length of the completion string, which included 12 swellable packers for 13 zones. To provide for a safer, less-expensive, and efficient method of tripping pipe, the operator chose a downhole-isolation-valve (DIV) solution that allowed for the process to be performed in a conventional manner under conditions of complete well control.
Introduction
During the past decade or so, the industry has developed drilling methods to address more-complex and - challenging prospects such as ultradeep prospects, deepwater applications, and high-pressure/ high-temperature wells in order to continue meeting the worlds’ demand for energy. This seemingly insatiable demand has led to the development and widespread use of unconventional techniques such as underbalanced drilling (UBD) or near-balanced drilling and various forms of managed-pressure drilling, including pressurized-mud-cap drilling (PMCD) and constant- bottomhole-pressure drilling with their attendant well-control and safety challenges. Some of these challenges are
Moderate to severe lost-circulation conditions and consequent nonproductive time (NPT)
Formation damage as a result of having to kill the well before tripping pipe
Pore-pressure and fracture-gradient similarity leading to kick and loss cycles and well-control problems
A necessity for snubbing techniques to trip the pipe in and out of the hole above the “pipe light” depth, with the attendant added cost and risk
Overall operational safety and environmental issues
Operational economics and the effect of resulting NPT
As a result of these challenges, mitigating drilling hazards has become an extremely important facet of drilling operations and has prompted the development of procedures and equipment designs to address them, one of which is the DIV.
Managed-Pressure-Drilling Technology Delivers Challenging HP/HT Drilling Campaign
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175479, “MPD Technology Used To Deliver Challenging HP/HT Drilling Campaign,” by Robert Graham, Martin Geddes, Tim Harris, Dominic Flaherty, Nigel Shuttleworth, Bruce McEwan, Noor Nordin, Michael Cadd, John O’Grady, and Pete French, Shell, and Richard Sandell and Stuart Jeffries, Blade Energy Partners, prepared for the 2015 SPE Offshore Europe Conference and Exhibition, Aberdeen, 8–11 September. The paper has not been peer reviewed.
The Shearwater field is a deep, high-pressure/high-temperature (HP/HT) reservoir located in the UK Central Graben of the North Sea. A high level of reservoir depletion (greater than 8,000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to exploit the remaining reserves successfully. Managed-pressure-drilling (MPD) technology was implemented in conjunction with drill-in liner and wellbore-strengthening technologies to successfully deliver the first well in a redevelopment campaign and prove the techniques required to prolong field life.
Shearwater Overview
Shearwater is an HP/HT gas/condensate field discovered in 1988. Primary production is from the Fulmar, a sandstone reservoir with virgin pressure of 15,400 psi and temperatures greater than 360°F. The field came on stream in 2001. The large field-pressure depletion resulted in compaction at the Fulmar formation level and led to mechanical failure of the production liners because of shear deformation.
A drilling campaign to restore Fulmar production was initiated in 2013. The primary plan was to abandon the existing reservoir sections of the wells and perform shallow sidetracks from the 20-in. casing. A 16-in. hole was planned to the top of the Tor formation (above the pressure ramp), and a 12¼-in. hole was to be drilled into the top of the Cromer Knoll formation. 10×10¾-in. casing would be set across this hole section, and an 8½-in.-hole section would be drilled to just above the top of the Kimmeridge shale formation. A 7?-in. drill-in-liner system would then be used in conjunction with MPD and wellbore- strengthening material to drill into the top of the Fulmar reservoir. The reservoir was planned to be drilled with a 6½-in. hole size opened out to 7½ in., and the reservoir would be completed with a 7×5-in. production liner. The MPD objectives by hole section are discussed in detail in the complete paper.
MPD was planned as an enabling technology because of the tight fracture-pressure/ pore-pressure wellbore- stability window. Fig. 1 illustrates the planned wellbore configuration and the expected pressure profiles.
New Rotary Shouldered Connection Expands Capability of ERD Operation
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE/IADC 168049, “New Rotary Shouldered Connection Expands the Capability of World-Record ERD Operation,” by S.R. Sanford, SPE, and M.W. Walker, SPE, ExxonMobil; and J.N. Brock, M.J. Jellison, SPE, and A. Muradov, SPE, NOV Grant Prideco, prepared for the 2014 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 4–6 March. The paper has not been peer reviewed.
Eight of the world’s 10 longest wells have been drilled by ExxonMobil as operator of the Sakhalin-1 project in Russia. Components and drilling tools involved in the well design are evaluated and redesigned throughout the program to maximize penetration rate and reduce flat time. Drillstring-torque capacity was recognized as a limiter for increasing penetration rate and for reaching total measured depth capability. The operator consequently sought an alternative drillpipe connection with higher torque capacity.
Introduction
The Sakhalin-1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields off the east coast of Sakhalin Island, Russian Federation (Fig. 1). Development drilling at the Chayvo field started in 2003 with extended-reach wells drilled from an onshore location with the Yastreb drilling rig. In 2005, further development drilling commenced from the offshore Orlan platform site. Subsequently, in 2008, the Yastreb rig was moved approximately 75 km north to the Odoptu onshore wellsite and drilled nine extended-reach-drilling (ERD) wells as part of the initial-stage development of Odoptu. During the Odoptu campaign, it was determined that a higher-torque 5?-in. drillpipe connection with good runnability was needed. Following the Odoptu campaign, the Yastreb rig was moved back to the Chayvo onshore wellsite in 2011 for further development and infill drilling of the Chayvo reservoirs.
Limiter Identification
During the first drilling campaign at Chayvo, available topdrive torque limited drilling performance in the long production hole section (&gt;3000 m). Installation of a new topdrive capable of continuous torque in excess of 90,000 lbf-ft at 140 rev/min eliminated this limiter. During the subsequent Odoptu drilling campaign, the 5?-in. drillpipe connection was identified as a new limiter affecting rate of penetration (ROP) and torque operating margin in the production hole section.
Norway Faces Up to Harsh Conditions
Authors: Rassenfoss Stephen 
Published: January 2017

Offshore Norway is an unlikely spot for optimism. The continental shelf is home to a mature basin, with harsh sea conditions, a reputation for high costs, and an exploration frontier well north of the Arctic Circle.
Last year’s version of low oil prices, when benchmark crudes traded for around USD 50/bbl, led to news stories in Norway pointing out that the shares of the 10 largest local oil-industry-related companies, excluding Statoil, were worth less than the 10 biggest aquaculture companies.
While raising salmon is expected to grow into a big business, with big oil industry suppliers such as Kongsberg working on high-tech tools to raise millions of fish, those working in the oil business are not talking about a career change.
“Oil [/bbl] is selling for the same prices as 4.5 kilo salmon. We could all start farming salmon, but I do not think so,” said Arve Iverson, ROV operations manager for Oceaneering, at the recent Subsea Valley Conference in Oslo.
The show put on by the organization created to increase the visibility of the engineering-driven oil industry in southeast Norway, also amounted to a rally in support of the future of oil offshore Norway, and the global markets these companies_serve.
Eldar Sætre, the chief executive officer (CEO) of Statoil, pointed out that the national oil company has lowered its average break-even cost for new projects from USD 70/bbl to USD 40/bbl, and emphasized that the bulk of the improvement was in savings that will remain after supplier discounts are gone.
The themes of standardization, simplifying requirements, and working together were common ones when hearing from oil industry experts.
The test of whether the Norwegian industry can deliver on its goal of profitably producing oil in a era of low prices, is the Johan Sverdrup field, a multibillion-barrel find which is moving forward in the midst of the slump, showcasing innovations backed by the Norwegian government and Statoil.
Technology Focus: CO2 Applications
Authors: Kokal Sunil 
Published: January 2017

Overview
Carbon dioxide (CO2) has been in the news a lot. We have all heard about global climate change. Chances are your child in elementary school has also heard about it. It has been center stage in all local, national, and international political and environmental debates. I am not going to talk about it here. What I am going to articulate here is what we can do about it in our own way. By “we,” I mean we as individuals, we as SPE members, and we as oil and gas industry professionals.
First, the bad news: Indeed, there are a lot of challenges with CO2. It is a stable compound and does not readily disintegrate. The biggest challenge perhaps is the cost of capturing CO2. Most of the anthropogenic CO2 is available from fixed sources such as power plants. The CO2 first has to be separated from nitrogen, then compressed, and finally piped and pumped into a subterranean reservoir for oil recovery or storage. All of these steps are expensive.
Now the good news: It can be done. And we, as petroleum engineers and Earth scientists, are best suited to do it. We know our reservoirs, we have produced from them, and we can ensure that CO2 can be sent back safely and securely into them. Supercritical CO2 is an excellent solvent, especially for lighter crude oils. If it were free, or as low in cost as water, we would be injecting CO2 instead of water for its favorable properties.
So how can we help? There are many areas and applications of CO2 in the oil and gas industry. CO2 enhanced oil recovery (EOR) is the bedrock and the mainstay in our application portfolio. A lot has been published in that area. At present, there remain several challenges with CO2 EOR. These include gravity override, poor sweep efficiency, and economic factors. Considerable work and research are ongoing to address all of these challenges. The papers that follow address some of them: an example of chemical-looping emerging technology in a bid to reduce CO2-capture costs; CO2 foams for improved oil recovery; commercial-scale demonstration projects; and use of CO2 in tight gas and unconventional resources. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 169039 Development of Small- Molecule CO2 Thickeners for EOR and Fracturing by J.J. Lee, University of Pittsburgh, et al.
SPE 169022 Experimental Investigation of Enhanced Recovery in Unconventional Liquid Reservoirs Using CO2: A Look Ahead to the Future of Unconventional EOR by Francisco D. Tovar, Texas A&M University, et al.
SPE 171692 Carbon Capture and Storage for Enhanced Oil Recovery: Integration and Optimization of a Post-Combustion CO2-Capture Facility at a Power Plant in Abu Dhabi by A. Reichl, Siemens, et al.
A Novel Integrity-Assurance Approach for Qualification of Subsea Technologies
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27296, “Development of a Novel Integrity-Assurance Approach for Technology Qualification of New Subsea Technologies by Deepstar,” by S. Furtado and H. Hamedifar, DNV GL; K. Mateen, Total; L. Huyse, Chevron; L.M. Rivero, Total; and G. Kusinski, Chevron, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed.
A study has been conducted to develop a methodology in which integrity of the various components of a new technology can be quantified, even in the absence of failure data from the field. The study recognizes the importance of having a common understanding and definition of key principles used in technology qualification (TQ) and a common view of integrity-assurance-acceptance criteria in the oil and gas industry.
Introduction
The deepwater industry uses TQ as a tool to determine which safety barriers are needed, as well as what level of testing is required. TQs have traditionally focused on technical systems and capabilities at the component level. Much less attention has been given to systematic factors, however.
Knowledge of systems involves understanding of the integrity of technologies during design, construction, operation, and maintenance. It is accepted that there is a lack of common ground and consistency in qualifying new technologies in the subsea industry.
Qualification Approaches in Other Industries
Other industries, such as the nuclear, aerospace, and automotive industries, have a more established reliability-engineering history and address failure rates and mean life of systems and products in a numerical or quantitative manner. These industries make use of the following methodologies:
Immense amounts of monitoring data
Much lengthier qualification processes
Natural and frequent check and monitoring points
Uniformity of application
Weibull distribution
Regression analysis
Essentially, the three industries named deal with many components and systems that have undergone a lengthy qualification effort. Moreover, there is significant monitoring of the performance parameters. The systems and equipment in these industries have a much more uniform application range than those of the offshore industry. Finally, there are natural and repeated intervention or access points to the equipment for repair, maintenance, and checkup.
In the oil and gas offshore industry, applications are not uniform, access and monitoring are very limited, and the number of equipment items with meaningful failure data is minuscule compared with, say, hundreds of millions of automobiles on the roads.
How the Petroleum Industry Can Learn From the Ebola Crisis of 2014
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177759, “How the Petroleum Industry Can Learn From the Ebola Crisis of 2014,” by Andre Willemse, International SOS, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.
The Ebola crisis of 2014 was one of the worst infectious disease outbreaks in recent history. It also occurred in a region with endemic medical risks and poor medical infrastructure. These two factors make it an important learning exercise for the global petroleum community. This paper reviews the Ebola outbreak from the viewpoint of an onshore and offshore petroleum operator, providing insight into the real threats the outbreak presented by looking past the media hype and diving into the real organizational effects of the outbreak.
Introduction
West Africa experienced the most severe Ebola virus disease (EVD) outbreak ever recorded. The most-affected countries are Liberia (10,672 cases as of 16 August 2015), Sierra Leone (13,494 cases), and Guinea (3,786 cases). Other affected countries include Mali, Nigeria, and Senegal in Africa; and Italy, Spain, the United Kingdom, and the United States, although to a much lower level. Pictorial representation of the number of cases and deaths in affected countries as of 5 July 2015 is shown in Fig. 1.
The World Health Organization on 6 August 2014 declared this Ebola outbreak in West Africa to be a public health emergency of international concern.
Lessons Learned
The West Africa Ebola outbreak has been the largest, longest, and most complex since the virus was discovered in 1976. It has had the highest number of cases and deaths ever reported for Ebola.
A functional health system is a prerequisite for any coordinated preparedness for and response to any possible outbreak. The 2005 revision to the International Health Regulations (IHR) is a legally binding agreement whose purpose is “to prevent, protect against, control, and provide a public health response to the international spread of disease in ways that are commensurate with and restricted to public health risks, and which avoid unnecessary interference with international traffic and trade.” None of the most-affected countries were compliant with the IHR regulations, and this surely delayed the timely identification of the disease, the setting up of contact tracing and adequate surveillance measures, and the early implementation of infectious control measures in healthcare settings.
Comments: Dubai Hosts Annual Meeting
Authors: Donnelly John 
Published: January 2017

Later this month, the SPE Annual Technical Conference and Exhibition will be held in the Middle East for the first time. The conference will take place 26–28 September at the Dubai World Trade Centre. The locale not only underscores the region’s undaunted significance in the global oil and gas industry but also SPE’s continued international growth.
SPE has had a presence in the Middle East region for more than 50 years. In 1958, the SPE Board of Directors reorganized its basic organizational structure to take into account SPE’s rapid growth in membership. The board divided the Society into 11 separate regions, including one that encompassed Saudi Arabia. This was shortly before the creation of the Organization of Petroleum Exporting Countries (OPEC), of which Saudi Arabia was one of four founding member countries.
In 1961, SPE held its first significant program outside of North America. The first Regional Petroleum Technology Meeting, sponsored by the SPE Saudi Arabia Section, took place in Dhahran, with registration totaling 132 people representing 14 companies. The Saudi section had grown to 150 members in a little over a year since its creation.
Middle East membership growth continued and, in 2003, SPE created its first office in the region in Dubai to serve not only the Middle East but also North Africa. The region’s membership totals more than 13,000 professional members and more than 4,000 students, participating across 17 sections and 34 student chapters.
The Middle East has long been the focal point of the global oil industry and the latest BP Statistical Review of World Energy highlights the region’s dominant presence, as well as points out some changes taking place. Middle East energy consumption grew 4.2% in 2015, roughly in line with its 10-year average, and is growing faster than other regions around the world. About half of Middle East energy consumption is now natural gas, surpassing demand for oil. Oil output in the region grew 1.5 million BOPD last year to a record high 30.1 million BOPD, according to the Review, with production growth led by Iraq and Saudi Arabia.
The Middle East holds about 47% of the world’s proven crude reserves, almost 16% of those by Saudi Arabia alone, with Iran and Iraq holding 9.3% and 8.4% of the global total, respectively. The region has approximately 43% of total global gas reserves, with Iran claiming more than 18% and Qatar 13%.
This is the third time SPE has held its premier annual meeting outside the US. The conference took place in Florence, Italy, in 2010, and in Amsterdam in 2014. The meeting is not only an annual gathering for members but a platform for the latest technology trends and breakthroughs as well as a forum for discussing contemporary issues.
This year’s conference is no different, with panel sessions on operating and thriving in difficult times, preparing for a low-carbon era, changes companies are making to survive in a low-price environment, and handling data and analytics. For a complete schedule of technical sessions and events, please go to www.spe.org/atce/2016. JPT
Technology Update: A Holistic Approach To Controlling Torsional Dynamics in the Drillstring
Authors: Lines Liam 
Published: January 2017

Technology Update
Understanding drilling dynamics, the downhole shock and vibration that occur while drilling, is a crucial step to improving drilling efficiency and reducing nonproductive time (NPT).
Industry statistics suggest that 20% to 30% of all downhole failures are related to adverse drilling dynamics (SPE 127413 and SPE 98150), and that drilling tool providers spend roughly USD 750 million per year on repair and maintenance. This amount pales compared with the untold costs borne by exploration and production companies as the result of drilling and completion inefficiencies, NPT, and tools lost in the hole.
Preventing adverse dynamics requires a strong understanding of the fundamentals, particularly in addressing torsional dynamics: time-based variations in downhole rotational speed and torque.
A common misconception is that torsional dynamics is limited to stick/slip. However, stick/slip is only one of three distinct modes of torsional dynamics, each with its own unique indicators, potential for damage, effect on drilling efficiency and—importantly—most effective means of mitigation.
Differing Dynamics
In addition to full stick/slip (FSS), the modes include low-frequency torsional oscillation (LFTO) and high-frequency torsional oscillation (HFTO) (Fig. 1). LFTO and FSS both typically occur at less than 2 Hz; HFTO occurs at between 50 and 250 Hz.
LFTO, probably the most common of all three modes, is the excitation of a fundamental torsional natural frequency of the drillstring. The excitation causes the drillstring to act as a long torsional spring, which results in sinusoidal oscillations in bit speed and torque. The oscillation frequency is a function of the drillstring length and stiffness, and is typically less than 0.5 Hz for all drillstrings (SPE 21945). LFTO is characterized by a maximum revolutions per minute (RPM) of up to twice the average drillstring RPM and a bit that may stop, but only instantaneously.